otahuhu substation diversity project

Otahuhu Substation Diversity Project © Transpower New Zealand Limited 2007. All rights reserved. i

OTAHUHU SUBSTATION DIVERSITY PROJECT

APPLICATION FOR INCREASE OF MAJOR CAPEX ALLOWANCE

Transpower New Zealand Limited

September 2012

Otahuhu Substation Diversity Project © Transpower New Zealand Limited 2012. All rights reserved. 1

Table of Contents

1 Executive Summary .......................................................................................................... 1

1.1 Background ................................................................................................................... 1

1.2 This application ............................................................................................................. 2

2 Project Identification and Specifications ............................................................................ 4

3 The amendment sought .................................................................................................... 5

3.1 Quantum of proposed amendment to major capex allowance...................................... 5

3.2 Calculations showing how the quantum of the proposed amendment was calculated . 5

3.3 Post-GUP approval planning ......................................................................................... 5

3.4 Assumptions made in the calculations .......................................................................... 6

3.5 Evidence in support of the calculations ......................................................................... 6

3.6 Proposed P50 ................................................................................................................ 7

3.7 Calculations, key assumptions and supporting evidence used to determine proposed

P50, by reference to specified P50 .......................................................................................... 7

4 Progress of the project ...................................................................................................... 8

4.1 The planning processes undertaken ............................................................................. 8

4.2 Resource management and other regulatory consents ................................................ 9

4.3 Property and access rights obtained or being sought ................................................. 10

4.4 Construction completed to date .................................................................................. 10

4.5 Construction and labour contracts and arrangements made ...................................... 11

4.6 Any testing processes ................................................................................................. 12

5 Current and forecast expenditure .................................................................................... 13

5.1 General ........................................................................................................................ 13

5.2 Forecast major capex .................................................................................................. 13

5.3 Baseline budget and cost breakdown during the planning stages of the Project ....... 13

5.4 Further refinement of Project works and budget ......................................................... 14

5.5 Overview of total Project cost history .......................................................................... 15

5.6 Evaluation of budget estimates ................................................................................... 16

5.7 Major capex incurred to the date of the application .................................................... 16

5.8 Difference between the major capex allowance and the major capex incurred.......... 16

6 Reasons for the application ............................................................................................. 18

6.1 Overview of factors that caused Project costs to exceed the major capex allowance 18

6.2 Category A - Enabling Works Civil General Overspend ............................................. 19

6.3 Category B - Transmission line deviations .................................................................. 24

6.4 Category C - Enabling works secondary systems design and install ......................... 25

6.5 Category D - Enabling works transition station and cable termination ....................... 27

6.6 Category E – Enabling Works Procurement ............................................................... 29

6.7 Category F –Design/Build Contract for GIS/AIS and EHV Cable ............................... 30


6.8 Category G – Land easement ..................................................................................... 31

6.9 Category H - Interest During Construction .................................................................. 32

7 Information about the effect of the amendment application ............................................ 34

7.1 Description of the implications of the proposed amendment will have on the Otahuhu

project outputs ........................................................................................................................ 34

7.2 Net electricity market benefit ....................................................................................... 34

7.3 No change to the assets to be commissioned ............................................................ 35

7.4 No change to the functional capability of the grid ....................................................... 35

7.5 No change to any relevant service provided by a third party (for non-transmission

services) ................................................................................................................................. 35

7.6 No implications for other approved major capex projects ........................................... 35

8 Evaluation of the application ........................................................................................... 36

8.1 Application is consistent with the Capex IM ................................................................ 36

8.2 The proposed amendment promotes the long-term interests of consumers and more

generally the purpose of Part 4 of the Commerce Act 1986 .................................................. 36

8.3 Data, analysis, and assumptions are fit for purpose ................................................... 37

Correspondence between Hon David Parker and David Gascoigne……………….Appendix A

Project Management Plan……………………………………………………………….Appendix B

Cost Management Procedure document………………………………………………Appendix C

IQANZ Review…………………………………………………………………………….Appendix D

Chapter 1 : Executive Summary


1 Executive Summary

1.1 Background

On 12 June 2006, an equipment failure at our Otahuhu substation resulted in a widespread

loss of electricity supply to Auckland and Northland. At the time of the outage we were

considering future developments at Otahuhu to facilitate the 400 kV transmission line from

Whakamaru to Auckland (the North Island Grid Upgrade Project).

The highly costly outage significantly increased the urgency of the work planned at Otahuhu

in advance of the North Island Grid Upgrade Project. To this end, we gave an undertaking to

the Minister of Energy to proceed with urgency on actions to increase security of supply.1

Our investigation of options to increase diversity and improve the reliability of supply into

Auckland and Northland led to the submission of a Grid Upgrade Plan (GUP) to the

Electricity Commission on 11 December 2006 (within 6 months of the outage event). We

proposed to establish a new GIS/AIS 220kV switchyard at Otahuhu within an approval cost

of $99 million (P90) in 2009 year dollars.

Given the urgency of the project and our desire to commission the new switchyard at the

earliest opportunity, our submission was based on relatively high-level cost estimates. While

the Electricity Commission was considering its decision, we proceeded to further develop the

design of the switchyard. The proposal was approved on 31 August 2007.

This was only the second of twenty GUPs2 approved by the Electricity Commission under

Part F of the Electricity Governance Rules and the first project of its size and type

undertaken for many years. As a result, we did not anticipate many of the “brownfield”

issues that arose from working in an existing, older substation such as relocation of

unidentified underground services, the extent of stormwater filtration required, and extensive

integration required with existing in-service substation facilities.

As evident within the body of this application, the most significant component of the project,

the GIS at a cost $64.2 million came in close to budget when taking into account the effect of

foreign exchange and inflation.

We have now completed the new 220 kV switchgear facility at our Otahuhu substation which

is physically and geographically separate from the existing switchyard. Circuit connections

have also been diversified between the two switchyards so that a major failure in either one

does not result in a total loss of supply. The last asset for this project was commissioned in

November 2011.

We have incurred costs of $106.1 million on the Project, $7.1 million in excess of the major

capex allowance (P90) of $99 million. We originally sought to recover the overspend by way

of application to the Electricity Commission in July 2010 when the project was 96%

complete. The advice we received was to submit it to the Commerce Commission when the

project was 100% complete.

1 Refer correspondence between David Parker and David Gascoigne attached in Appendix A.

2 Of these twenty GUPs, there are three forecast to exceed the respective approval costs.



While the final cost is seven per cent greater than the P90 submitted in the GUP, use of this

higher cost would not have altered the recommendation and approval of the decision to build

the new substation at Otahuhu.

1.2 This application

This is an application for an amendment to the major capex allowance for the Otahuhu

Substation Diversity Project (the Project). This application is being submitted pursuant to the

Transpower Capital Expenditure Input Methodology Determination3 (the Capex IM).

We have incurred costs of $106.1 million on the Project, $7.1 million in excess of the major

capex allowance (P90) of $99 million. A number of factors have contributed to this increased

expenditure and these are discussed in detail within the body of this application. In

summary, the key factors are:

unforeseen environmental requirements for stormwater filtration facilities

the need to relocate existing underground utilities services which were not detailed and

in some cases not identified on drawings of the site

a significant underestimate of the cost to install four 220 kV transmission towers

complex and challenging design and installation enabling works for secondary systems,

including protection, SCADA and communications

exchange rate fluctuations associated with the design/build contract for the major

construction component of the Project

the need to award a contract to complete the construction enabling works prior to

completing the detailed design (and associated scoping of the necessary works) due to

the urgency required to mitigate the single point of failure risk to Auckland

the unexpected need to include the costs of a property easement

an underestimate of Interest During Construction (IDC) due to an over-simplified “rule-

of-thumb” calculation.

While many of these factors relate to the planning and estimation phase of the Project, it

should be noted that an independent review of the costs by Parsons Brinckerhoff Associates

(PB Associates) post-GUP submission concluded that its own cost estimates were close to

those submitted and the remaining differences were well within the accuracy levels of the

estimates.4

The GUP provided for an approved expenditure of $99 million in 2009 dollars. This was the

P90 estimate. The P50 capital cost for the Project was estimated at $94 million in 2009

dollars. The difference between the P50 and P90 costs reflects the value of the uncertainty

associated with price, exchange rate variability, inflation and financing costs.

Given that the Project required extensive construction work on a “brownfield” site, the 5%

difference between P90 and P50 costs, and the 10% scope allowance in the P50 was

unrealistically low in hindsight given the level of budget uncertainty and lack of detailed

investigations at the time of the GUP submission.

3 Transpower Capital Expenditure Input Methodology Determination [2012] NZCC 2, dated 31 January 2012.

4 Otahuhu Substation Diversity Project: Review of the Capital Cost Estimates for Transpower’s Proposal of 11 December

2006, Parsons Brinckerhoff Associates (May 2007), section 4. A copy of this report is available at http://www.ea.govt.nz/industry/ec-archive/grid-investment-archive/gup/2005-gup/otahuhu-substation-diversity-proposal-history.



Once the construction phase had begun, we implemented project governance and project

cost management processes that were assessed by an independent external review to be

robust, and successfully developed innovative scope refinement processes to control costs

and scope creep.5 This supports our view that project cost management following the

commencement of the construction phase was not a factor in total Project costs exceeding

the major capex allowance, and that the Project was executed efficiently.

As discussed in detail within this application:

we consider all Project costs are reasonable and have been efficiently incurred

this project is still preferred among the options presented in the GUP despite the cost

overrun

from Project delivery, detailed budgets were established based on a more developed

scope of works, and we managed the Project implementation efficiently, seeking to

minimise Project costs through competitive tendering and other project cost

management initiatives

we responded to the emergence of unforeseen factors in a prudent and efficient

manner, actively minimising associated costs while working towards delivering the

approved major capex project outputs anticipated by the GUP.

Against this backdrop, we:

request the Commission amend the major capex allowance for the Project to $106.1

million to enable recovery (and receive a return) on all actual costs incurred for this

Project

consider it is consistent with the Capex IM and the purpose of Part 4 of the Commerce

Act for the Commission to amend the major capex allowance for the Project.

5 Refer Appendix D - Transpower – Otahuhu Diversity Project: Independent Quality Assurance Health Check Review,

Independent Quality Assurance New Zealand (2009), at page 3.

Chapter 2 : Project Identification and Specifications


2 Project Identification and Specifications

The key project specifications that formed part of the Electricity Commission-approved GUP

were for the Project to:

remove all over-crossings of the existing substation at Otahuhu

install bus section circuit breakers in the existing 220kV switchyard

procure, construct, commission and operate a new 220kV gas insulated switchgear

(GIS) switchyard and a new air insulated switchgear (AIS) switchyard at Otahuhu,

connected and adjacent to, but geographically separated from, the existing switchyard

transfer approximately half of the circuits from the existing switchyard to the new

switchyards

obtain designations, and resource consents necessary for the above

plan for commissioning of the new switchyard by 2009.

The only material work to be completed is the removal of some redundant assets, namely

one span over the 110 kV bus that remains. This overhead section is to remain as a

contingency measure to cover for a potential cable failure. The removal was scheduled for

the later of, either:

approximately 1 year following the successful commissioning of the above cable circuit

the commissioning of the cable section from Pakuranga to Albany as part of the NAaN

project in order to provide additional security to Northland and North Auckland.

The cost of this outstanding work, estimated at $0.1 million, is included in the current project

cost.

The Electricity Commission approved expenditure on the Project of $99 million or the actual

cost, whichever was the lesser. Approval was given on the basis of a 90th percentile cost

estimate which was made up as shown in the table below.

Table 2-1: Otahuhu Substation Diversity Project P90

Category Cost $m (2006)

Contingency

$m (2006)

Exchange rate

variation

$m (2006)

Interest during

construction

$m (2006)

90% cost limit

$m (2006)

Inflation

90% cost limit

$m (2009)

Design 1 0 0 0 1 0 1

Enabling works 7 1 0 1 9 1 10

Substation works AIS 7 1 0 0 8 1 9

Substation works GIS 30 3 2 2 37 4 41

Transmission lines/cabling 24 2 1 1 28 3 31

Project

management 6 0 0 0 6 1 7

Total 75 8 3 4 89 10 99

Chapter 3: The amendment sought


3 The amendment sought

3.1 Quantum of proposed amendment to major capex allowance

The total expenditure on the Otahuhu Substation Diversity Project is $106.1 million.

Accordingly, we have incurred an additional $7.1 million above the major capex allowance of

$99 million.

We request the major capex allowance for the Project be increased by $7.1 million to enable

recovery of the $106.1 million total cost incurred in relation to the Project.

3.2 Calculations showing how the quantum of the proposed amendment was calculated

The GUP estimate was prepared using component costs from our cost estimating tool

wherever possible. For costs not covered by the cost estimating tool, high-level cost

estimates were used.

3.3 Post-GUP approval planning

While the Electricity Commission was considering the GUP, we proceeded to further develop

the design, scope and cost of the project by way of a Solution Study Report (SSR). This

formed the basis of the budget that was included in the internal business case, known as the

Project Approval Document (PAD), which was prepared following the Electricity

Commission’s GUP approval.

The PAD budget was lower than the GUP P50 estimate by $9.4 million (in 2006 dollars) and

was broken down into different expenditure categories than those provided in the GUP.

It was the PAD budget that was used by the implementation manager to manage the delivery

of the project and to this end, a meaningful direct comparison between the individual

categories of expenditure in the GUP cost estimates and the actual costs incurred is not

possible.

Given that the project was managed to the PAD budget, it is appropriate that the comparison

of actual costs be shown against the PAD budget.

Table 3-1 below shows the difference between the PAD budget and actual costs.

The third column shows the PAD budget in $2006 – this is the budget to which the project

was managed. Given this, where we describe the overspend in detail, it is this budget we

are comparing the actual expenditure to – as shown in columns four and five.

Column six shows the PAD budget in approximate 2009 year dollars –effectively the PAD

budget adjusted for the CPI movement between June 2006 and June 2009. This allows a

useful comparison to the actual capital spend, most of which occurred in 2009. This

comparison is shown in the final column.



Table 3-1: PAD budget as compared with actual expenditure (NZ $m)

Overspend Category/ Adjustment to PAD Estimate

PAD Budget 2006 $

Actual Overspend relative to PAD

Adjusted PAD to 2009 $

Overspend relative to adjusted PAD

A Enabling Works Civil General 3.5 11.0 7.5 3.8 7.2

Stormwater Drainage 0.1 3.1 3.0 0.1 3.0

Wastewater 0.3 1.8 1.5 0.3 1.5

Underground Services Relocation 0.2 1.8 1.6 0.2 1.6

Warehouse Building Relocation 1.2 1.5 0.3 1.3 0.2

Earthworks and General 1.8 2.9 1.1 2.0 0.9

B Transmission Line Deviations 2.4 4.2 1.8 2.5 1.7

220 kV tower piled foundations 0.1 2.4 2.4 0.1 2.4

Other work 2.3 1.8 -0.5 2.5 -0.7

C

Enabling Works Secondary Equipment Design & Install 2.8 7.7 4.9 3.0 4.6

D

EW Transition Station & Cable Termination Design & Install 3.2 7.1 3.9 3.4 3.6

Cable terminations 1.2 2.1 0.9 1.3 0.8

Transition Stations 1.6 3.9 2.3 1.8 2.2

AIS switchyard works 0.3 1.0 0.7 0.3 0.7

E Enabling Works Procurement 3.4 3.9 0.5 3.7 0.2

Protection equipment 0.6 1.0 0.4 0.6 0.4

Other procurement 2.8 2.9 0.1 3.1 -0.1

F Design Build GIS/AIS & EHV Cable 58.2 64.2 6.0 62.9 1.3

G Land Easement 0.0 1.2 1.2 0.0 1.2

H Interest During Construction 3.2 6.9 3.7 3.5 3.5

TOTAL 76.6 106.1 29.5 82.8 23.3

3.4 Assumptions made in the calculations

The figures provided in Table 3-1 above reflect actual costs incurred by Transpower (plus an

estimate for incomplete works).

The PAD budget has been adjusted to 2009-year dollars for comparison purposes in Table

3-1 above.

The property easement value included in Table 3-1 above (and discussed more fully in

Section 6.8) is from an independent valuation and hence is based on standard valuation

principles.

3.5 Evidence in support of the calculations



An Excel spreadsheet, Otahuhu_MCA_Increase_Calcs_Sep12.xlsx, detailing the actual

costs incurred against the PAD budget, has been provided to the Commerce Commission as

part of this application. Another spreadsheet, GIT recalc 20120820.xlsx, has been provided

showing the GIT results for the project updated with actual costs.

Supporting detail by work package, contract price schedule items, contract variations, and

related documentation is also available if required by the Commission.

3.6 Proposed P50

The proposed P50 is the same as outlined in the original GUP, being $94 million. Given that

this is not an application for an increase in the MCA to cover future expenditure, a proposed

P50 for this application is not relevant.

3.7 Calculations, key assumptions and supporting evidence used to determine proposed P50, by reference to specified P50

The calculations, key assumptions and supporting evidence used to determine the proposed

P50 are also addressed in the original GUP.

Chapter 4: Progress of the project


4 Progress of the project

4.1 The planning processes undertaken

4.1.1 Background to planning for the Project

The GUP was submitted to the Electricity Commission under some urgency following the

outage in June 2006 which resulted in a loss of supply to most of Auckland. The failure of an

overhead earth wire crossing over the existing AIS switchyard at Otahuhu caused the

outage. The outage illustrated the criticality of the existing substation.

As a prudent owner and operator of the grid, we agreed with calls for the vulnerability of the

Otahuhu substation to High Impact Low Probability (HILP) events to be addressed as a

matter of highest priority. The correspondence attached as Appendix A provides

background as to the circumstances in which we undertook planning for this Project.

4.1.2 High level design

As a first step in the planning process, we undertook high-level design to establish the scope

and initial costing of the Project. To meet the tight Project timeframes, cost estimates from

the North Island 400 kV Grid Upgrade Project (NIGU Project) were used as a basis for some

elements of the Otahuhu Diversity Project.

As an example, the initial requirement for the NIGU Project included 400 kV terminal stations

(and their associated 220 kV stations) at Otahuhu and Whakamaru substations.

Investigations for various 400 kV and 220 kV substation arrangements at Otahuhu

commenced in 2004 so in 2006, when it was decided the reliability of the existing 220 kV

Otahuhu substation had to be increased, we were able to draw on this.

Some issues associated with constructing a 400/220 kV terminal substation at Otahuhu had

therefore been identified and many of these had been investigated by external consultants.

These included geotechnical investigations, relocation of buildings, relocation of manholes

and sewers, earthworks, etc. Investigations by external consultants considered engineering

aspects and also provided preliminary cost estimates. These investigations were however

specific to 400/220 kV terminal station options and not the Otahuhu Diversity Project 220 kV

options.

4.1.3 Cost estimation methodology

As part of the NIGU Project, a cost estimating tool was developed to enable costing of the

400/220 kV substation options. This tool was peer reviewed by Mott MacDonald (Brighton)

and Burns, Roe Worley (Australia) and updated as appropriate.6 The cost estimating

methodology was discussed with, and component costs used in the cost estimating tool were

given to, the Electricity Commission.

The methodology used to prepare the 400 kV and 220 kV substation project costs for the

NIGU Project was generally as follows:

6 Transpower can provide the Commission with an internal Transpower report (Transpower Report ADG-S-039 of June

2006), should the Commission wish to understand more about this peer review.



The substations were broken down into a number of discrete building blocks and

component costs were established for each building block. Component costs included

the cost of the primary plant item(s), minor procurement items and a percentage mark-

up to cover the design/build contractor’s design, project management and installation

costs.

For primary plant, actual procurement costs for similar/identical plant purchased by

Transpower were used wherever possible. This was limited to 220 kV air insulated

switchgear (AIS) equipment.

Where recent actual costs were not available, budgetary costs for primary plant were

obtained from suppliers typically used by Transpower.

The average of the primary plant actual and/or budgetary costs was included in the

component costs.

The above methodology only covered standard substation building blocks and did not cover

variable costs such as civil works, relocation of buildings and underground services,

deviation of transmission lines, etc. Estimated costs for such items were input separately

into the cost estimating tool for inclusion in the total estimate.

4.1.4 GUP cost estimates

The methodology described above was generally used to develop the GUP estimate for the

Otahuhu 220 kV Diversity Project. The GUP estimate was prepared using component costs

from the cost estimating tool wherever possible. For costs not covered by the cost

estimating tool, high-level cost estimates were used.

Standard building block costs were used to estimate the cost for the new 220 kV GIS,

extensions to the existing 220 kV AIS, and the 220 kV cables.

For components not listed in the cost estimating tool, estimated costs were input as

separate items. Costs from previous projects were used wherever possible. Time did

not however allow for these costs to be investigated and estimated in detail by external

consultants.

For the “Enabling Works” (site clearance and earthworks, relocation of Wastewater

Services manhole, relocation of Contact’s sewer, relocation of buildings and relocation

of existing transmission lines crossing the site), estimated costs were either derived

from the preliminary cost estimates prepared for the 400 kV NIGU Project or included as

a provisional cost (PC) sum. Again, time did not allow the costs to be reinvestigated

and re-estimated by external consultants.

4.1.5 Post-GUP approval planning

Following GUP approval, an internal project approval was prepared in the form of the Project

Approval Document (PAD). The PAD included a more detailed cost estimate based on a

Solution Study Report completed after the GUP was submitted.

This PAD budget was the budget that the Project was managed to once the Project

proceeded to construction and the detailed design was prepared.

4.2 Resource management and other regulatory consents

We obtained the following consents as part of the Project:



A permit for the diversion and discharge of stormwater, issued in accordance with

sections 14 and 15 of the RMA 1991 and in accordance with the provisions of the

Proposed Auckland Regional Plan: Air, Land and Water (October 2004).

Land use consent: Sediment control associated with earthwork for enabling works

(permit No. 34991). This consent was issued in accordance with Auckland Regional

Plan Rule 5.4.2.1.

Land use consent: Installation and operation of substation. This consent was issued by

the Manukau City Council.

In addition, we submitted the GUP to the Electricity Commission for approval under Part F,

Section III of the Electricity Governance Rules. On 31 August 2007, the Electricity

Commission approved the GUP for the Project.7

4.3 Property and access rights obtained or being sought

We entered into a formal agreement with Contact Energy Limited (Contact) for access rights

over their land to:

undertake a minor relocation of 110 kV tie lines

construct a temporary by-pass line

upgrade/divert Transpower’s existing stormwater system off Contact’s land

assist in the re-location of a Manukau City Council sewer pipe.

We entered a sale and purchase agreement with Manukau City Council to initially occupy,

and following Council subdivision thereof, acquire land for the purposes of the Project.

Occupation and ownership of the land allowed us the necessary rights to construct and

deviate our existing transmission lines across the land, and to construct and connect a new

stormwater system into the public network.

The land cost attributable to the Project was determined by obtaining a property valuation of

the easement on the land that would have been required had we not become the owner.

4.4 Construction completed to date

The final asset completed as part of this Project (the cable section of the Southdown circuit)

was commissioned on 20 November 2011.

The project is not fully ’closed out’ as we are dealing with some handover items and may be

for some time yet. None of these affect serviceability of the assets and associated costs are

relatively minor as they are largely the contractor’s liability.

The only material work to be completed is the removal of one span over the 110 kV bus.

This overhead section is to remain as a contingency measure to cover for a potential cable

failure. The removal was scheduled for the later of, either:

7 The Major Electricity Users Group (MEUG) filed to the High Court for a judicial review in November 2007 which

was rejected in March 2008. An appeal to the Court of Appeal was dismissed in December 2008.



approximately 1 year following the successful commissioning of the Otahuhu to

Southdown cable circuit

the commissioning of the cable section from Pakuranga to Albany in the NAaN project

to provide additional security to Northland and North Auckland.

The cost of this outstanding work, estimated at $0.1 million, is included in the project total

cost.

4.5 Construction and labour contracts and arrangements made

4.5.1 Major contracts entered into by Transpower

There were three main contracts involved in this Project:

the design contract with AECOM (formerly Maunsell)

the Enabling Works Construction Contract with Transfield

the Design/Build Construction contract with AREVA.

4.5.2 Project management processes

Following completion of the “development” phase of the Project, we prepared a Project

Management Plan (PMP) to support the delivery phase of the Project. The PMP was written

for Project participants from Transpower and the three main contractors – AECOM,

Transfield and Areva. It encompassed project plans, processes and systems for planning,

monitoring and managing the delivery of the Project through to operational acceptance. A

copy of the PMP is attached as Appendix B.

In addition, an Enabling Works Construction Cost Management Procedure was developed to

define the process by which Transpower and Transfield managed contract costs on the

Enabling Works Construction Contract for the Project. This procedure included ongoing

management of change through scope refinements or variations as well as payments

processing and forecasting. A copy of the Enabling Works Construction Cost Management

Procedure is attached as Appendix C.

4.5.3 Independent review of project management processes

We sought an independent ‘Health Check Review’ of the ongoing project cost management

processes implemented by Transpower approximately a year after the award of the enabling

works contract. This review was conducted by IQANZ. A copy of the IQANZ report

accompanies this application as Appendix D.8

The IQANZ report states:

“In summary, this is a large and complex project that is being well run by an

experienced and capable project team.” 9

“Robust cost control procedures for scope refinements and contract variations are in

place.”10

8 Transpower – Otahuhu Diversity Project: Independent Quality Assurance Health Check Review, Independent Quality

Assurance New Zealand (2009).

9 IQANZ Report, at page 3.



“The Project budget has been appropriately mapped back to the project work

breakdown structure.”11

“We find cost control and reporting to be robustly governed and managed by the

project.”12

Accordingly, we consider that the ongoing project cost management processes implemented

and followed after the commencement of the construction phase were reasonable and not a

contributing factor to the Project costs exceeding the major capex allowance. That is, known

project costs were efficiently managed, and scope refinements and variations to deal with

inevitable unforeseen factors and other refinements and variations typical for a construction

project of this scale were assessed by an independent review to be robust.

4.6 Any testing processes

We have conducted standard testing processes on the assets commissioned as part of this

Project, in accordance with Transpower standards, manufacturers’ specifications and good

electricity industry practice.

Most of the assets that have been commissioned under this Project have been in service for

more than two years and all are delivering the grid outputs that form the basis of the GUP

without incident.




Chapter 5: Current and forecast expenditure


5 Current and forecast expenditure

5.1 General

Almost all of the capital expenditure for this Project which we wish to recover has been

incurred. No significant additional material expenditure for this Project is anticipated by

Transpower other than an estimated $0.1 million for removing redundant assets as

described in Section 4.4.

Set out below is a description of the forecast major capex (and how this was calculated), and

the actual major capex we incurred, for the Project.

5.2 Forecast major capex

5.2.1 Background

A detailed explanation of both the background to the cost estimation process and the

methodology we used to forecast the expenditure for the Project is set out earlier in Section

4.1.

It is our view that the scope and price contingencies made in the cost estimates used in the

GUP did not reflect the true uncertainty associated with the level of design on which those

estimates were based. Given where we were in the early stages of design, many of the

factors that resulted in the overspend which relate to construction works on a “brownfield”

site were reasonably unforeseeable. However, our cost estimate did not accurately reflect

this and in hindsight, a larger contingency should have been included to reflect the level of

budget uncertainty at that early stage of investigations.

It should also be noted that the type and scale of these works had not been undertaken by

Transpower in its recent history so we had very little upon which to base our assessment of

the risks, as borne out by the unrealistically small difference between the P50 and P90

forecast costs.

5.3 Baseline budget and cost breakdown during the planning stages of the Project

The original GUP approved by the Electricity Commission included an estimated “P90” cost

for the project of $99 million. This comprised (in 2006-dollars):

a base estimate of $75 million

contingencies of $8 million

exchange rate risk of $3 million

interest during construction (IDC) of $4 million

inflation of $10 million to bring the cost to 2009 dollars.

A high-level cost estimate was prepared as input to the GUP using the cost estimation

process as described in Section 4.1.

The capital cost estimates used in the GUP were reviewed, at the Electricity Commission’s

request, by Parsons Brinckerhoff Associates (PB Associates). As part of this review, PB

Associates prepared its own estimates based on information available to PB Associates at



the time. PB Associates concluded that its cost estimates were close to those submitted by

Transpower and the remaining differences are well within the accuracy levels of the

estimates.13

5.4 Further refinement of Project works and budget

Table 5-1 below shows the high-level timeline associated with the Project.

Table 5-1: Project History

Date Project Status

12 June 2006 Equipment failure of shackles at OTA causes widespread outage in Auckland and Northland

December 2006 Transpower submits GUP application

May 2007 Interim approval of GUP

May 2007 Request for public conference

August 2007 Final approval from EC

August 2007 SSR conceptual design completed

August 2007 PAD Budget

November 2007 Judicial review of EC decision filed by MEUG

December 2007 Enabling design and construction contracts for civil site works awarded

March 2008 High court rejects judicial appeal and EC’s final decision stands

October 2008 All major contracts awarded. Project 21% complete. Re-estimate for Board submission for additional funding

May 2010 96% of assets commissioned

November 2011 Fully commissioned

As can be seen in the timelines, we continued to develop the design of the Project while the

GUP was being considered by the Electricity Commission.

Following Electricity Commission approval, we prepared two core project documents:

1. The Solution Study Report dated 31 August 2007 included more developed scope

and some changes (e.g. different cable routes) whilst still delivering the same project

outputs included in the GUP.

2. A Project Approval Document (PAD) was prepared for internal Transpower approval,

based on the Solution Study Report.

The PAD included a more detailed cost estimate of $76.6 million (including contingency and

IDC but not inflation) which was lower than the GUP P50 estimate by $9.4 million. Inflation

was not included because it was not standard practice to adjust for inflation when reporting

actual expenditure compared to budget.

13 Otahuhu Substation Diversity Project: Review of the Capital Cost Estimates for Transpower’s Proposal of 11

December 2006, Parsons Brinckerhoff Associates (May 2007), section 4. A copy of this report is available at http://archive.electricitycommission.govt.nz/opdev/transmis/gup/otahuhudiversity.



The PAD budget was prepared using a conceptual design as documented in the SSR and

before detailed design was complete and the detailed scope of work for the Project was fully

developed. This was of much greater significance for accurate cost estimating than would

have been the case if the Project had been a new build at a ‘green field’ site where

parametric estimates based upon other similar projects would have been more accurate.

Furthermore, as the works were carried out on a “brownfield” site, we were confronted by

unforeseen site-specific factors that were not adequately taken into consideration in the

scope contingencies when preparing the estimates used in either the GUP or the PAD

budget.

Due to development of the design over the period between GUP and PAD estimate

preparation, there were significant differences in the level of detail between the two

estimates and they were not reconciled to identify and explain variances at a detailed level.

The PAD budget was used as the baseline budget to support ongoing Project cost

management rather than the less detailed budget used for the GUP approval. The PAD

budget was mapped to the ‘activity’ based project work breakdown structure comprising 87

individual ‘Work Packages’. PAD budgets are a control mechanism within Transpower, and

do not reflect fully the probability of unforecast contingency expenditure.

Throughout the Project, the cost forecast was reviewed monthly, revised as required and all

change amounts and reasons were recorded and reported to a project governance group.

5.5 Overview of total Project cost history

Project cost estimates at five key stages in the project development and execution phases

were as per the table below.

Table 5-2: Project cost history

Date

Description/Project Status Amount Variance to PAD

14

December 2006

GUP P90 $99m -

August 2007 PAD Budget15

$76.6m -16

December 2007

Enabling design and construction contracts awarded

$81.6m $4.9m

October 2008

All major contracts awarded. Project 21% complete. Re-estimate for Board submission for additional funding

$100.3m $23.7m

May 2012 Final Cost $106.1m $29.5m

14 The comparison here is between actual costs and the PAD budget outlined in Table 3-1.

15 Does not include allowance for inflation.

16 As the PAD budget did not include an allowance for inflation, it is not meaningful to compare this PAD budget amount

against the GUP P90.



As indicated in Table 5-2, we were aware of the majority of the overspend against the P90

estimate by October 2008, at which time the work was already 21% complete. At this point

we could not have stopped and followed another option as the GIS contract letter of

acceptance was dated 5 May 2008.

We investigated various means of remaining within the approved budget; however, other

than ensuring effective cost and contract management,17

there was little in the way of

mitigation options available to significantly reduce cost from that time.

The Transpower Board was briefed on the situation at the November 2008 meeting and

approved additional funding based upon the revised cost forecast.

5.6 Evaluation of budget estimates

There was effectively an independent check on the construction cost elements of the PAD

budget through the competitive RFP process for establishing the Enabling Works

Construction contract which was awarded to Transfield and the Design Build contract which

was awarded to Areva.

5.7 Major capex incurred to the date of the application

The major capex for the Project incurred to the date of the application is $106.1 million. As

noted earlier, we do not anticipate incurring additional material expenditure for this Project.

5.8 Difference between the major capex allowance and the major capex incurred

Given that the PAD budget was based on the more refined scope of works for the Project,

and was the actual budget that the Project was managed to, it is a far more meaningful

comparator.

Table 5-3: PAD budget vs. actual expenditure (NZ $m)


PAD Budget 2006 $


Adjusted

PAD18

2009 $


A Enabling Works Civil General 3.5 11.0 7.5 3.8 7.2

B Transmission Line Deviations 2.4 4.2 1.8 2.5 1.7

C Enabling Works Secondary Equipment Design & Install

2.8 7.7 4.9 3.0 4.6

D EW Transition Station & Cable Termination Design & Install

3.2 7.1 3.9 3.4 3.6

E Enabling Works Procurement 3.4 3.9 0.5 3.7 0.2

F Design Build GIS/AIS & EHV Cable

58.2 64.2 6.0 62.9 1.3

17 See Section 4.5 for a discussion of the project management processes established by Transpower, and a summary of

the key conclusions of an independent review of these project management processes.

18 This column is adjusted for the CPI movement between June 2006 (the date of the 2006 PAD prices) and June 2009

(the year of greatest project expenditure).




PAD Budget 2006 $


Adjusted

PAD18

2009 $


G Land Easement 0.0 1.2 1.2 0.0 1.2

H Interest During Construction 3.2 6.9 3.7 3.5 3.5

TOTAL 76.6 106.1 29.5 82.8 23.3

The most significant overspend occurred in the Enabling Works categories A to D in the

above table which cost $29.9 million against an original budget of $11.9 million.

Categories E and F cover enabling works procurement and design/build work with budget

$61.6 million and final cost $68.1 million. As explained in more detail in the following

section, most of the expenditure in excess of the estimate can be attributed to escalation

from budget in $2006-dollars versus actual payment largely made in $2009-dollars.

The key reasons for actual Project costs exceeding the major capex allowance are explained

in detail. Supporting detail by work package, contract price schedule items, contract

variations, related documentation and PAD budget are available if required.

Chapter 6: Reasons for the application

Otahuhu Substation Diversity Project © Transpower New Zealand Limited 2012. All rights reserved.

18

6 Reasons for the application

6.1 Overview of factors that caused Project costs to exceed the major capex allowance

There are a number of reasons that contributed to our actual Project costs exceeding

the major capex allowance. In summary, these were:

unforeseen environmental requirements for stormwater filtration facilities

the need to relocate existing underground utilities services which were not

detailed and in some cases not identified on drawings of the site

a significant underestimate of the cost to install four 220 kV transmission towers

complex and challenging design and installation enabling works for secondary

systems, including protection, SCADA and communications

exchange rate fluctuations associated with the Design/Build contract for the

major construction component of the Project

the need to award a contract to complete the construction enabling works prior

to completing the detailed design and associated scoping of the necessary

works due to the urgency required to mitigate the single point of failure risk to

Auckland

the unexpected need to include the costs of a property easement

an underestimate of Interest During Construction (IDC) due to an over-simplified

“rule-of-thumb” calculation.

In addition, the urgency of the Project delivery timetable required the award of the

enabling works construction contract prior to completion of the detailed design and

associated scoping of the works. This resulted in multiple scope variations and

ultimately an underestimate of the Project costs.

The enabling works for the Project required significant earthworks, transmission line

deviations, and other works relating to secondary equipment, transition stations and

cable terminations. These enabling works are indicated as categories A to E in Table

5-2. Project costs relating to each of these categories are discussed in more detail

below.

The earthworks component of these works was constrained by the construction

season, so in order to achieve our target project delivery timeframe, we had to award

the enabling works construction contract in December 2007, while work on the

detailed design and project scope carried on in parallel.

These contracts19

were awarded through a competitive RFP process.

Awarding the enabling works construction contract ahead of detailed design was

particularly problematic due to the site being a “brownfield site”. The complexities of

working around, and integrating with, existing in-service facilitates, make accurate

cost estimation very difficult in the absence of detailed design.

In this section we describe each of these key factors in more detail, by cost category

listed in Table 5-3.

19 Copies of the material contracts can be provided to the Commission if necessary.



19

6.2 Category A - Enabling Works Civil General Overspend

($11m expenditure against budget of $3.5m)

This category covers the civil engineering and building site works required to

establish the new switchyard and associated infrastructure for the GIS building and

AIS equipment. It excludes:

cable terminations and transition stations work (covered under category D)

cable trough construction (covered in the Design/Build works under category F).

Cost history for the enabling works civil general category of Project costs is shown in

the table below.

Note that the August 2007 PAD costs are in 2006 dollars whereas the bulk of costs

were incurred in 2009. Table 3-1 above shows the PAD costs, for this and

subsequent tables, adjusted for the CPI movement from June 2006 to June 2009.

Table 6-1: Enabling Works Civil General

Date Description Amount Variance to PAD

August 2007 PAD Budget $3.5m -

December 2007

Main design and construction contracts for civil site works award

$4.9m $1.4m

October 2008

Construction underway – re-estimate for Board submission for additional funding

$9.7m $6.1m


The RFP process included pricing from three contractors.

The vast bulk of the spending in excess of the original estimate was not identified at

the time we awarded the Enabling Works construction contract to Transfield.

Expenditure in excess of the estimate was identified 10 months later when design

and civil construction were 20% complete. As detailed below, the factors that caused

the overspend in this category could not have been reasonably foreseen at the time

we put together the PAD budget.

This category of Project costs can be subdivided into five subcategories as follows,

with PAD budget and final cost as shown.

Table 6-2: Subcategories of Enabling Works Civil General

Description PAD Budget Actual Variance20

Stormwater Drainage $0.1m $3.1m $3.0m

Underground Services Relocation $0.2m $1.8m $1.6m Wastewater $0.3m $1.8m $1.5m

Warehouse Building Relocation $1.2m $1.5m $0.3m Earthworks and General $1.8m $2.9m $1.1m

Total $3.5m $11.0m $7.5m

20 Variance is the comparison between the PAD budget allowance and actual costs.



20

Below we explain further the key factors for the variation between estimated costs

and actual costs for each of the subcategories of works.

6.2.1 Unforeseen environmental requirements for stormwater filtration facilities

($3.1 million expenditure against budget of $0.1m)

The requirement to treat stormwater runoff for contamination was not anticipated

when we prepared the cost estimates for the Project. The PAD budget allocated

$0.1 million for stormwater drainage works. These works cost $3.1 million.

The initial scope of work for the Project involved little change to the surface water

runoff characteristics of the existing site in terms of both topography and

permeability. Some paved surfaces and a GIS building roof were to be added which

would have increased the peak runoff; however, most of the area to be developed

(i.e. new switchyard) is covered in highly permeable isolation chip above a subgrade

of in situ material.

For this reason, in the SSR it was anticipated that only minor stormwater drainage

works would be required with surface drainage discharged directly into an existing

retention pond adjacent to the site. The PAD budget reflected this with a single

nominal lump sum cost line item.

However, substantially more works were required than anticipated to obtain and

comply with the conditions of, the necessary resource consent. In particular,

stormwater filtration facilities were required to treat contaminated runoff from the

galvanised equipment installed in the switchyard. This included supply and

installation of a large underground tank structure for storage and filtration.

Substantial underground stormwater reticulation plus a new discharge point under

the adjacent motorway was also required. These were required by the Auckland

Regional Council (ARC) and Manukau City Council (now Auckland Council).

Transpower deals with stormwater discharge at all substation sites, but not usually at

the scale encountered at Otahuhu. There are several discharge locations over the

whole Otahuhu site. However, there were no existing discharge consents for this site

before the Project, so there was little information about the stormwater systems and

location of discharge.

The requirement to treat stormwater runoff for contamination was not anticipated

based on the original scope of the works and Transpower’s previous experience with

stormwater discharge.

Had we identified and included specific provision for the underground stormwater

infrastructure required for the GIS building, and the relocation of a warehouse and

car park, this would only have increased the overall cost estimate by approximately

$0.6 million. However, expenditure for this budget item was still vastly

underestimated due to the unforeseen filtration system requirements. The remaining

$2.4 million of overspend could not have been reasonably foreseen based upon the

information available at the time.

The areas at the Otahuhu site now owned by Transpower and Contact were formerly

collectively owned by ECNZ. In the ECNZ split, Transpower became the owner of



21

the area now housing the Otahuhu warehouse and substation. Contact became the

owners of property at Otahuhu including the land where a cooling pond is

located. We hold an easement across the Contact land for various services including

stormwater drains. During the course of the Project, Contact advised they did not

want runoff from the new development going directly into an existing cooling pond as

it would breach their resource consent conditions, and if we were to discharge

through their cooling pond it could put their operation at risk i.e. the amount of new

impervious surfaces to be created as part of the Otahuhu diversity project would

require ‘controlled’ runoff.

We challenged the environmental requirement for contamination treatment in

October 2007 when we became aware of the stormwater issue. However, the

challenge was unsuccessful and we were required to undertake these additional

works to meet resource consent conditions.

We had to investigate new discharge points and we worked with Manukau City

Council and New Zealand Transport Agency to assess if the new Highbrook

interchange stormwater system could be used to discharge stormwater (an

alternative to discharging through Contact’s land). Other discharge site options were

also looked at but would have required extra piping and pumps to ensure discharge

as they all lead to the Tamaki River.

Further, the Otahuhu site was viewed by the Auckland Regional Council (ARC) as

one with potentially high levels of heavy metal contamination likely to be discharged

from the stormwater system. The council required us to undertake monitoring of the

discharge in terms of contamination levels.

We considered installing a filter system as a mitigation measure; however, before

making this decision we sampled the discharge from the site to ascertain the likely

level of contamination. The results from the tests showed high levels of copper and

zinc above the ARC guidelines. Several different treatment systems were assessed

to ensure only areas requiring treatment were treated and ensure the most cost

effective system was installed to meet the legal requirements of the Resource

Management Act.

These works were competitively tendered under our scope refinement process.

6.2.2 Relocation of underground utilities services

($1.8m expenditure against budget of $0.2m)

During construction, several underground utilities services were found that had not

been identified in the SSR. As a result, the Project incurred significant cost to

investigate and deal with this issue.

The approved scope of work for the Project included installing over 2 km of 220 kV

underground cable troughs around the site, plus other underground services. The

Otahuhu substation is large and old with many underground services and a number

of owners. Design and installation was necessary to accommodate or relocate

existing services. These included Vector-owned power cables, water mains,

telecommunications fibre, stormwater pipes and oil interceptor pipes.



22

Following the submission of the GUP, the process of developing the SSR identified

the presence of some of these underground services. However, not all underground

services were identified, and in many instances for those that were, exact locations

and depths could not be ascertained in advance. Determination of the precise

location of all services was not within the scope of the SSR and, as it transpired, not

possible as underground services were discovered that were unknown even to their

owners.

It was assumed that most existing services could be built around and the PAD

budget included a lump sum provision for services relocation (mainly for water

supplies) of $0.2 million.

With subsequent detailed design and identification of exact location of existing

services, substantial relocation of several services was required to accommodate the

new cable troughs. This included relocation of Vector-owned power cables at 11

locations. This was carried out by Vector at a cost to the Project of $0.7 million.

Based on the information available at the time of the GUP and PAD budgets, the

costs associated with underground services relocation were not reasonably

foreseeable.

The PAD budget assumed that most services would not require relocation was

incorrect. However, quantifying and accurately estimating this work would have

required both site investigations to establish the exact location of services and

detailed design work.

All works were competitively tendered, and those that fell under the enabling works

contract were subject to a scope refinement process as set out in the Enabling Works

Cost Management Procedure document attached as Appendix C.

6.2.3 Waste water

($1.8m expenditure on budget of $0.3m)

An 800mm diameter sewer main runs 12m underneath the site of works. It had a

manhole located inside the new switchyard. This was unacceptable to us and the

owner of the sewer, Watercare. There was also a sewer from the adjacent Contact

Energy Otahuhu Power Station into this manhole which required relocation to

another manhole.

The SSR identified the need to remove this manhole and replace it with 2 new ones

outside the switchyard which were required to maintain required distances between

manholes. This was budgeted at $0.3 million.

All aspects of this work were technically challenging, time consuming and expensive.

A specialist subcontractor for this type of work (Brian Perry Ltd) carried out the

required works and we consider they performed well in difficult circumstances.

The original contract price for the work was $0.5 million. The contract was subject to

several substantial contract variation claims which we challenged. The final cost we

paid was finally resolved by engaging an independent expert, Clive Tilby, to review

and recommend a fair settlement. His recommendation was accepted by both



23

parties and his advice was that it was a reasonable cost for the actual work

required.21

The cost of this type of work is inherently difficult to estimate. While the PAD figure

was $0.2 million lower than the original contract price, it was of the same order. This

suggests that the cost incurred due to the “unknowns” could not have been

reasonably foreseeable prior to undertaking the work.

6.2.4 Warehouse Building Relocation

($1.5 m expenditure on budget of $1.2m)

The new substation switchyard site had one existing building (the ‘K Shed’). This

was part of a warehouse facility including other buildings and outdoor storage space

adjacent to the site. The original project scope included removing the K Shed from

the switchyard site and building replacement covered storage.

The SSR investigated four options for K Shed removal and replacement with cost

estimates ranging up to $2.6 million.

The PAD budget of $1.2 million was based upon removing the K Shed and replacing

it with a 15 metre lean-to structure on an existing building, but there was little specific

design information available at the PAD budget stage.

Installing an addition to an existing building is inherently more difficult to accurately

estimate than constructing a new stand-alone facility and as little design information

was available for the PAD budget, the total expenditure of $1.5 million for this item is

considered to be reasonable.

6.2.5 Earthworks and General

($2.9m expenditure on a budget of $1.8m)

The earthworks scope included work to establish the platform for a new AIS

switchyard and GIS building including parking and access. Existing land was largely

an undeveloped grass paddock.

The PAD budget estimate comprised three high-level line items for topsoil stripping,

bulk earthworks and roading with assessed quantities and rates. This assumed cut

to fill balance with no cut to waste or imported material being required. The original

construction contract price was consistent with this.

However as detailed design was developed and work proceeded on site there were

many changes and issues resulting in 89 contract scope refinements and variations

that substantially increased the total cost. This included requirements for a retaining

wall, concrete nib wall, additional fencing, additional earthworks and imported clean

fill material, disposal of contaminated soil and substantially more car park and

roading work than initially assumed. Based upon the information available at the

21 A copy of Mr Tilby’s recommendation can be provided to the Commission if required.



24

time most of these were not reasonably foreseeable when the PAD estimate was

prepared.

Completion of detailed design and more detailed site investigations as input to the

PAD estimate would have increased the accuracy of the cost estimate for this item.

6.2.6 Conclusion

The overspend for general civil enabling works was the result of a number of factors.

The principal contributing factors were the environmental requirements for

stormwater filtration, and the need to relocate a large number of underground

services, neither of which could have been reasonably foreseen at the time the GUP

estimate or the more detailed PAD estimate.

The remainder of the general civil enabling works overspend resulted from scope

changes in the waste water, general earthworks and warehouse building relocation

aspects. While the scope of the actual works differed from that which was allowed

for in the GUP and the PAD, the actual costs incurred were in all cases reasonable

and the works were performed in the most cost effective manner possible using cost

and scope control procedures that were assessed by an independent review to be

robust.

We consider all Project costs in this category are reasonable and have been

efficiently incurred and an amendment to the MCA to allow full recovery is therefore

justified.

6.3 Category B - Transmission line deviations


This element of the Project covers the design, installation and project management of

the deviation of existing 110 kV and 220 kV transmission lines around the new

switchyard location to allow construction to proceed on the GIS building and AIS

installation. It does not include procurement of transmission line towers, conductor

and fittings which is discussed in ‘Category E - Enabling Works Procurement’ below.

The PAD budget of $2.4 million for this category was exceeded by $1.8 million to

reach a final cost $4.2 million (a 79% increase).

Table 6-3: Transmission Line Deviations

Date Description Amount Variance


December 2007 Enabling design and construction contracts for civil site works awarded

$3.4m $1.1m

October 2008 Design contracts awarded – re-estimate for Board submission for additional funding

$4.0m $1.7m


6.3.1 Underestimation of 220 kV tower installation cost




25

The expenditure in excess of the estimate is entirely due to an underestimate of the

cost to install four 220 kV towers. The PAD budget provision for this category was

only $0.1 million and the actual cost we incurred was $2.4 million. The total final cost

of other items in this category was less than the PAD budget amount.

The 220 kV tower installation cost was dominated by foundation works, being 87% of

the cost. The high cost of tower foundation works was due to weak in situ materials

at all four sites. This necessitated deep piled foundations rather than simpler and

cheaper shallow pads. The piled foundations as designed and constructed included

20 metre deep bored cast in situ reinforced concrete piles with permanent casings.

The PAD budget for these works was based upon another project, which did not

contemplate such deep bored pile foundations.

Foundation requirements were known at the time of SSR preparation or shortly

thereafter as they were included in the original installation contract scope and price.

This information was therefore reasonably foreseeable at the time the PAD budget

was prepared and a more accurate estimate of this work should have been included

in the PAD budget.

In summary, the actual cost and complexity of deviating transmission lines around

the new switchyard location was substantially greater than originally anticipated, as

seen with the cost of tower foundations. We consider that the costs were reasonable

and efficiently incurred given the competitive tendering of the works and the use of

cost and scope control procedures that were independently reviewed as being

robust.

The other items of actual expenditure for this category of costs came in under the

PAD budget (as indicated in Table 3-1).



justified.

6.4 Category C - Enabling works secondary systems design and install


This category includes the design, installation and project management of enabling

works secondary systems including protection, SCADA and communications. It does

not include equipment procurement (covered in category E).

Most of this expenditure was for the design and installation of electrical protection

systems. The SSR included only a high-level outline of the protection scope with

three line items in the PAD estimate.

The enabling works protection design and installation effort was complex and

challenging largely due to integration with, and modifications required to, the existing

system as well as providing for interfaces to the GIS protection included in the

Design Build contract. Its full scope and complexity was not appreciated at SSR



26

stage, nor when the construction contract was awarded, or even when the detailed

design contracts were established in 2008. It only became progressively apparent as

the work proceeded, and therefore could not have been reasonably foreseen at

estimate stage.

As shown in the estimate history in Table 6-4 below, the forecast cost only increased

moderately upon construction contract award. This included contractor installation

cost estimates superseding PAD estimate based upon the competitive RFP process.

This demonstrates that while the PAD estimate ultimately proved to be inadequate,

independent contractors with the same limited information (or design information)

estimated the cost at a similar level.

Once the protection design contracts had been established in 2008 there was a

better understanding of scope reflected by the $2.2 million increase in cost forecast

from December 2007 to October 2008.

However, the final cost was an additional $2.3 million above the October 2008

estimate.

Table 6-4: Enabling works secondary systems – design and build



December 2007

Construction contract awarded $3.2m $0.4m

October 2008

Design contracts awarded – re-estimate for Board submission for additional funding

$5.4m $2.6m


The enabling works secondary systems involved in the Project underwent many

changes over the life of the Project, as illustrated by a large number of variations and

scope refinements to the design and construction contracts. The design contracts

included 79 secondary system variations and the construction contract included 102

secondary system scope refinements or variations.

When establishing contract packages for the work in late 2007, we considered

awarding a separate secondary systems contract after an initial contract comprising

civil site works, transmission line deviations, AIS equipment works and transition

stations.

This would have allowed time to develop a detailed protection design and award an

installation contract based upon competitive fixed price tenders. However, this

approach would not necessarily have reduced costs since the risk of the unknown

would have been factored into the contract price. It would also have added a

significant degree of complexity by creating additional work interfaces between

contractors.

In summary, the enabling works and secondary systems design and install was not

adequately provided for in the PAD budget, largely due to the complexity of

integrating these works with the existing systems that were already in place.

Nevertheless the robust project management processes and use of competitive

tendering ensured that design and install of these secondary systems was achieved

in the most cost effective manner possible.



27



justified.

6.5 Category D - Enabling works transition station and cable termination


This expenditure category includes enabling works line termination and AIS

switchyard primary equipment works. It excludes related protection work,

procurement of associated primary equipment and the 220 kV cabling work.

The PAD budget of $3.2 million for this category was exceeded by $3.9 million giving

a final cost of $7.1 million. Estimate history is shown below in Table 6-5:

Table 6-5: Enabling works station and cable termination



December 2007

Construction contract awarded $3.8m $0.6m

October 2008 Construction commenced – re-estimate for Board submission for additional funding

$4.4m $1.2m


This category of Project costs is subdivided into three subcategories as shown in

Table 6-6:

Table 6-6: Subcategories of the enabling works station and cable termination

Description PAD Budget Actual Variance

Cable Terminations $1.2m $2.1m $0.9m

Transition Stations $1.6m $3.9m $2.3m

AIS Switchyard Works $0.3m $1.0m $0.7m

Total $3.2m $7.1m $3.9m

6.5.1 Cable Terminations


There are four cable terminations located in the existing AIS switchyard. They

comprise the electrical and structural transition between 220 kV cables and the AIS

bus.

Each cable termination comprises standard AIS equipment including circuit breakers,

current transformers, voltage transformers, disconnectors, surge arrestors plus a

gantry structure and foundations and support posts for the equipment items.

We have sound historical knowledge of installation costs for such equipment. The

awarded contract price for cable termination installation did not vary significantly from

the PAD estimate providing support that the PAD estimate was reasonable for this

work.



28

However, following contract award there were 61 construction contract scope

refinements and variations primarily due to the constraints and requirements of

constructing the cable terminations within the existing switchyard. These contributed

to an increase of $0.9 million or 75% over the PAD budget. This included $0.2

million to relocate equipment to accommodate the Southdown cable termination in

order to maintain acceptable vehicle access through the switchyard. This issue was

not identified until detailed design was carried out and could not have been

reasonably foreseen at the time of PAD estimate preparation.

6.5.2 Transition Stations


There were five new transition stations located outside the existing and new AIS

switchyards comprising the transition from overhead 220 kV transmission lines to

underground cables for connecting to the new GIS.

Each transition station includes a gantry to terminate the overhead lines, electrical

connections from lines to the cables, surge arrestors, earthing, platform with crushed

rock surface and fencing.

The PAD estimate was developed to a relatively detailed level of breakdown for the

transition stations with each transition station separately identified and included 15

price schedule items. The total PAD estimate was $1.6 million. The original contract

price based upon similar information was, however, significantly higher at $2.1 million

– an increase of $0.5 million. There were further increases of $1.8 million during

construction to the final cost of $3.9 million.

The $0.5 million variance from PAD estimate to original contract price was due to two

transition stations (Henderson and Southdown). The other three had very similar

PAD estimates and contract prices.

The primary reason for the Henderson variance was that the PAD estimate did not

include a second emergency gantry required at this transition station. This was

identified in the SSR and should have been included in the PAD estimate.

The main reason for the Southdown variance is that significant tower modifications

and transmission line works were required for this transition station. This was not

specifically included in the PAD estimate – but should have been.

The post contract award cost increases for transition stations of $1.8m included 73

variations to the construction contract for a variety of reasons but with a common

underlying cause that many of them lacked a detailed design when the contract was

awarded. For example, the SSR did not identify a need for transition station lighting

but it was determined that this was required at the detailed design stage.

6.5.3 AIS Switchyard Works


The project required some additions and modifications to the existing switchyard in

addition to the installation of cable terminations as described above.



29

The SSR identified as the major item for this work the installation of two new bus

section circuit breakers (CB478 and CB488). In addition, the works included

relocation of a circuit to a different circuit breaker, which was a relatively minor item.

The PAD budget estimate for the bus section CB work was $0.3 million comprising

six line items for standard equipment such as circuit breakers, disconnectors, current

transformers and foundations. The contract award price for these items was very

similar. There were, however, 12 contract variations with additional cost primarily

attributable to changes required to integrate with existing switchyard infrastructure.

The final cost was $0.5 million – an increase of $0.2 million.

The circuit relocation was not specifically identified in the PAD estimate but the

original contract price for this work was only $0.04 million based upon re-termination

and removal of redundant primary equipment. The actual scope of work was varied

to include removal of redundant structures and foundations at an additional cost of

$0.1 million.

An underrated existing disconnector (DS847) in Contact Energy’s switchyard also

needed to be replaced. This was not expected and not identified until late in the

project. The associated cost was $0.1 million.

The $0.3 million balance of expenditure in excess of the estimate on this item was

generally a consequence of integrating the new project assets into the existing

switchyard. Again, these costs were not reasonably foreseeable at the time the SSR

was prepared, given the high-level nature of these estimates.

In summary, the PAD budget did not fully account for the cost of constructing cable

terminations within the existing switchyard, and the works associated with the five

new transition stations and the works associated with the AIS Switchyard.

Nevertheless the use of competitive tender processes and robust cost and scope

control procedures ensured that the actual costs associated with these works were

reasonable and efficiently incurred.



justified.

6.6 Category E – Enabling Works Procurement


This category of Project costs covers the procured equipment supplied for enabling

works construction. This included transmission line towers, transmission line fittings,

primary equipment such as circuit breakers, disconnectors, CTs and VTs and

secondary equipment including protection and communications equipment.

This category had a relatively modest increase from the PAD budget of $3.4 million

to final cost $3.9 million, being $0.5 million in excess of budgeted amount or a 15%

variation.

Protection equipment procurement accounted for most ($0.4 million) of this increase

from a PAD estimate of $0.6 million to a final cost of $1.0 million. As discussed



30

above in relation to cost category C, the SSR and PAD estimate only included a high-

level outline of protection scope and protection procurement requirements were

under estimated as was design and installation. There were 136 protection relay

equipment items procured for the project – this was not envisaged when the SSR

was prepared.

Other than protection equipment, the overall cost of procurement items was close to

the PAD budget (i.e. within 3%) and taking account of escalation from base 2006-

dollars to when most of the equipment was procured in 2009 it was within budget.

In summary, there was only a relatively modest increase from the PAD budget for

enabling works procurement costs, and all these costs were reasonable and

efficiently incurred, by virtue of competitive tendering and cost control processes.



justified.

6.7 Category F –Design/Build Contract for GIS/AIS and EHV Cable


This was the single largest component of the total Project works (being the

Design/Build contract for the construction of the new GIS/AIS substation and 220 kV

cabling). The actual cost was higher than budgeted owing to exchange rate

fluctuations from the time of the award of the contract and inflation. Contract

variations all came within the PAD budget.

The cost history for this component is shown in Table 6-7 below:

Table 6-7: Cost history for Design/Build contract for GIS/AIS substation and 220 kV cabling


August 2007

PAD Budget $58.2m -

October 2008

Re-estimate for Board submission for additional funding

$62.1m $3.9m


Unlike the enabling works components of the Project (items A, C, D and E in Table 3-

1), this package of work was carried out on the basis of a fixed price design/build

contract awarded following a competitive tender.22

The PAD budget estimate for this category of expenditure, based on June 2006

prices, was $58.2 million and we incurred a final cost of $64.2 million. Of this, $1.6

million is attributable to exchange rate fluctuations after the award of the design/build

contract – particularly the strong Euro in 2009.

22 A Tender Evaluation Report for this tender process can be provided to the Commission if considered

necessary for its consideration of this application.



31

The remaining variance of $4.4 million is due to inflation between the PAD price date

and when the expenditure occurred, the bulk of which occurred in 2009.

While the GIS/AIS design/build Contract (DB1) was a ‘Fixed Price’ contract, the

contractor was very aggressive with variation claims. This demanded considerable

effort by the Transpower Engineer to Contract (ETC) to negotiate claims to minimise

project cost while being fair to the contractor and maintaining reasonable working

relationships.

Transpower successfully negotiated 63 contract claims with the contractor over the

duration of the contract. At the completion of the works there were five claims that

were unresolved totalling $4.75 million.

After significant effort on our part, the five claims were finally settled on 25 March

2011. Four were rejected and the fifth was settled for $0.113 million. We consider

this to be a very good outcome in terms of the original $4.75 million claim value and it

demonstrates our prudent contract cost management practice on this project.

Overall the total value of contract variations was $3.4 million or 6% of original

contract price. There were many issues and challenges with this contract and in that

context we consider this level of total variations to be very reasonable, while also

demonstrating good contract cost management.

Overall our view is that:

competitive tendering of this work along with a low level of subsequent contract

variations means the work was completed for a fair market price;

there were many contract issues and claims and the total number of contract

variations is low for a Design/Build contract of this nature, and overall very

reasonable in that context. This indicates well defined original scope with little

or no ‘scope creep’ and good contract cost management;

the costs incurred for this category of works were reasonable and efficiently

managed. As noted earlier, we developed a Project Management Plan that

included robust processes for managing project costs and scope refinements

and variations.



justified.

6.8 Category G – Land easement

($1.2m expenditure against $0m budget)

The Project proposal indicated that the proposed GIS switchyard did not require the

purchase of additional property. However, realigning one of the lines into the

substation required two new towers to be placed on adjacent land owned by the

Manukau City Council which would have required an easement over a portion of it.

In addition, the project required some space for temporary staging purposes.

During discussions, the Council offered to sell the entire block to us at a cost of $6.02

million plus GST. We accepted the offer with the view that this provided the most



32

effective way for us to obtain the access and easements required, with the option of

reselling if not further required. If the Council sold the block to another party, the

Project would have incurred significant time delay while the required access and

easements were negotiated for work to proceed.

The intention at the time was to on-sell the land as it was not part of the approved

Project and its costs could not be recovered because the Electricity Commission did

not allow any temporary use of land to be included in the project costs.

We are now considering keeping the land for future developments at Otahuhu and

have applied for approval for the purchase.23

However, given that part of the

purchase cost is attributable to the Project, we have agreed with the Commerce

Commission that the value of the easement should be included in the Project costs.

We have obtained a retrospective valuation of the easement as at December 2007

when the property was bought, which came to $1.2 million.



justified.

6.9 Category H - Interest During Construction

($6.9m expenditure against $3.2m budget)

Interest During Construction (IDC) was underestimated in the PAD because of an

over-simplified approach to the calculation.

The PAD budget IDC estimate of $3.2 million was calculated simply as 4.8% of the

base estimate. This was an overly-simplified way to calculate IDC as it did not take

account of the phasing of expenditure until capitalisation or that the duration of the

project extended to more than 1 year. The rate is also lower than our actual IDC rate

(intended to reflect that expenditure does not all occur at the start of the year).

The December 2007 IDC cost forecast was $1.7 million higher than PAD budget at

$4.9 million based upon the monthly expenditure forecast, the IDC rate at the time

(7.5% per annum) and the expected capitalisation date of March 2010.

The final IDC cost was $6.9 million. The increase of $2.0 million over the December

2007 forecast was primarily due to increased overall Project costs with secondary

reasons being an increased IDC rate later in the project (e.g. 7.65% in December

2009) and later capitalisation date of May 2010 for most of the Project assets.

The original PAD budget estimate of IDC did not take account of expenditure phasing

and whilst being a simple and reasonable approximate estimate for shorter duration

projects, it caused a significant under estimate of IDC by $3.7 million on this Project.

The need for an appropriate allowance for IDC is a foreseeable cost component of a

major capex project. In this case, in hindsight a more appropriate IDC rate and

project phasing should have been used in the PAD calculation.

23 Grid Upgrade Plan 2009, Instalment 7, Part X: Recovery of Otahuhu Land Purchase Cost



33

The impact of IDC on overall project costs is an inevitable consequence of the nature

of the Project – that is, higher than anticipated base costs for a multi-year project,

with costs unevenly spread over the duration of the Project.



justified.

Chapter 7: Information about the effect of the amendment application


34

7 Information about the effect of the amendment application

7.1 Description of the implications of the proposed amendment will have on the Otahuhu project outputs

The proposed amendment has no implication for the project outputs. The approved

outputs are still appropriate because they deliver the diversity of supply required.

7.2 Net electricity market benefit

The expected net market benefit (ENMB) of the Project estimated in the GIT was

negative $54.3 million. A recalculation of this with actual costs and the effect of the

later timing of the Project compared to the GIT comes to negative $61.8 million which

would rank it second behind extending the existing switchyard (the reference case)

but within 2% of it. Table 7-1 shows a revised ranking of the GIT options with actual

costs for the Project (GIS).

Table 7-1: Ranking of GUP Alternatives (NPV)

Extend Existing Switchyard

2nd AIS Switchyard

GIS Switchyard

2006 dollars (million)

Capital Cost 75.8 85.2 82.5

Consenting & noise abatement 0.0 0.5 0.0

Operations & Maintenance 1.9 2.8 2.1

Total cost 77.7 88.5 84.6

Saved Expected Unserved Energy 10.3 19.8 16.5

Terminal value 2.9 1.7 2.1

Terminal benefit 4.0 4.0 4.1

Total benefit 17.2 25.6 22.8

Expected Net Market Benefit (60.5) (62.9) (61.8)

For purposes of comparison, we have assumed that commensurate cost increases

and delays would also have occurred with the AIS option but that they would not

have occurred for the reference case: extending the existing switchyard.24

While the

reference case option comes ahead of the Project when using actual costs, it should

be noted that some benefits attributable to the GIS option were not specifically

included in the GIT analysis although the GUP made reference to them, namely:

Property costs. For the reference case and AIS option, the cost of new land

required to replace the existing switchyard in the future was estimated at $7.7

million (ref section 8.5 of the GUP).

24 The $1.2 million easement cost would have been required for all options.

Chapter 7: Information about the effect of the amendment application


35

Immunity to site-wide, high impact, low probability events, for example severe

weather that affects all AIS switchgear and bus work. The annualised NPV of

this was estimated at $1 million (ref section 8.3 of the GUP).

Taking these benefits into account the GIS option would still be the highest ranking

option, by $7.5 million, using actual costs.

7.3 No change to the assets to be commissioned

Approval by the Commission of the proposed amendment to the major capex

allowance will not result in a change in the assets to be commissioned by

Transpower for this Project.

7.4 No change to the functional capability of the grid


allowance will not result in a change in the functional capability of the grid.

7.5 No change to any relevant service provided by a third party (for non-transmission services)


allowance will not result in a change in any services provided by a third party (for

non-transmission services).

7.6 No implications for other approved major capex projects

We do not consider the proposed amendment will have any implications for other

major capex projects.

The cost estimation process has undergone continuing development since this

project was costed. In particular, more consideration now tends to be given to the

risk profile around project item scope.

Chapter 8: Evaluation of the Application


36

8 Evaluation of the application

8.1 Application is consistent with the Capex IM

We believe that this application is itself consistent with the Capex IM. In particular:

This application has been submitted to the Commission in accordance with

clause 3.3.4(1) of the Capex IM.

We have complied with clause 7.4.2 of the Capex IM. Specifically:

(a) This application has been sent to the Commission before the last

working day of the September after the disclosure year in which the

Project was first commissioned (being before the last working day of

September 2012);

(b) The application contains the information specified in Schedule H

Division 1 of the Capex IM.

8.2 The proposed amendment promotes the long-term interests of consumers and more generally the purpose of Part 4 of the Commerce Act 1986

We consider that this application for an increase in the maximum capex allowance for

the Otahuhu Substation Diversity Project promotes the purpose of Part 4 of the

Commerce Act, being to promote the long-term benefit of consumers in markets

where there is little or no competition and little or no likelihood of a substantial

increase in competition, by promoting outcomes that are consistent with outcomes

produced in competitive markets.

We note that:

The Commission considers this central purpose is to be achieved by promoting

outcomes consistent with those produced in workably competitive markets, such

that the regulatory objectives set out in paragraphs (a) to (d) of section 52A(1) of

the Commerce Act are achieved.25

The individual price-quality path (of which the Capex IM provision for ex-post

amendment to the maximum capex allowance for major capex project forms

part) promotes the long-benefit of consumers by providing incentives to invest,

by allowing us to fully recover and earn a return an appropriate return on its

investments, consistent with section 52A(1) of the Commerce Act.26

The Capex IM regime implicitly recognises that accurately estimating the costs for

Transpower’s major capex projects is a difficult exercise, and therefore the Capex

IM provides for both an ex-ante assessment of estimated costs, and an ex-post

assessment of actual costs.

The objective of the individual price-quality path to promote the long-benefit of

consumers by providing incentives to invest, is therefore best achieved by

allowing Transpower to be confident in its ability to recover reasonable and

25 Commerce Commission, Individual Price Quality-Path (Transpower) Reasons Paper, 22 December 2010,

paragraph 1.2.23.

26 Commerce Commission, Individual Price Quality-Path (Transpower) Reasons Paper, 22 December 2010,

paragraph 1.2.24.

Chapter 8: Evaluation of the Application


37

efficient actual costs incurred in our major capex projects, as determined on the

basis of an ex-post assessment of actual costs.

In the case of the Otahuhu Diversity Substation Project, once the Project commenced

and more detailed budgets were established based on a more developed scope of

works, we have managed the Project implementation efficiently and have sought to

minimise Project costs through competitive tendering of the key components of the

Project and other project cost management initiatives.

We have responded to the emergence of unforeseen factors in a prudent and efficient

manner, actively minimising associated costs while working towards completing this

important project and delivering the approved major capex project outputs.

In summary, we are of the view that the long-term benefits of consumers are

promoted by allowing us to fully recover and earn a return on our investment in the

Otahuhu Diversity Substation Project, as this incentivises us to prudently invest in

necessary upgrades of the grid, by allowing us to fully recover our investments, where

those investments have been undertaken efficiently.

8.3 Data, analysis, and assumptions are fit for purpose

We also consider that the data, analysis, and assumptions underpinning the proposal

are fit for the purpose of the Commission exercising its powers under Part 4 of the

Commerce Act, including consideration as to the accuracy and reliability of data and

the reasonableness of the assumptions and other matters of judgement.

Otahuhu Diversity Project Delivery Phase

PROJECT MANAGEMENT PLAN

Version 2.0

October 2008

Project Management Plan Otahuhu Diversity Project

Document Control Version History Version Description Author Date 1.0 For Delivery phase planning Jitesh Raniga August 2007 2.0 For Delivery phase execution - major

revision with project participants and processes established

Graeme Oakden October 2008

Recommendation This document defines the: • Project background, scope and general requirements • Project governance, organisation, roles and responsibilities; • Project management processes and systems to be applied during project execution.

Recommendation for approval:

Name Title/Role Reference Date

Graeme Oakden ETC/ Project Management Support ODP-ETC084 15 November 2008

Approval:

Name Title/Role Signature Date

Jitesh Raniga Project Manager ODP-PMR011 17 November 2008

Distribution Name Title/Role Organisation

Jitesh Raniga Project Manager Transpower

Graeme Oakden Engineer to Contract/Project Management Support Transpower

Malcolm Stewart Technical Manager Transpower

Garry Wright Engineer’s Representative Transpower

Kevin Morris Project Manager – Enabling Works Design Maunsell

Colin Kemp Project Leader – Enabling Works Construction Transfield

Anil Asija Project Manager – DB1 AREVA

The PMP should be further distributed to project participants within Transpower, Maunsell, Transfield and AREVA and to the subcontractors as required to support their project roles.

ODP Project Management Plan v2_0.doc Page 2 of 26 October 2008


Contents: 1. Introduction .......................................................................................................4 1.1. Document Purpose ...............................................................................................4 1.2. Audience ..............................................................................................................4 1.3. PMP Content and Associated Documents ...........................................................4 2. Project Background, Scope & Requirements .................................................6 2.1. Background..........................................................................................................6 2.2. Scope of Work .....................................................................................................6 2.3. Business Case and Project Approvals..................................................................7 2.4. Project Work Breakdown Structure .....................................................................7 2.5. Project Schedule ..................................................................................................8 2.6. Project Budget......................................................................................................8 2.7. Contractual Approach ..........................................................................................8 2.7. Dependencies .......................................................................................................9 2.8. Key Delivery Objectives......................................................................................9 3. Project Participants, Governance & Organisation.......................................10 3.1. Project Participants ............................................................................................10 3.2. Project Organisation Structure...........................................................................10 3.3. Project Steering Committee ...............................................................................10 3.4. Enabling Works Management Team..................................................................10 3.5. DB1 Contract Management Team ....................................................................11 3.6. Project Communication .....................................................................................11 3.7. Project Stakeholders...........................................................................................12 4. Project Management Processes ......................................................................14 4.1. Project Progress Reporting ................................................................................14 4.2. Scheduling .........................................................................................................15 4.3. Cost Management ..............................................................................................16 4.4. Quality Management..........................................................................................17 4.5. Procurement Management .................................................................................17 4.6. Change Management .........................................................................................18 4.7. Deliverables Management .................................................................................19 4.8. Safety Management ...........................................................................................19 4.9. Risk & Issue Management .................................................................................19 4.10. Communications and Records Management......................................................20 4.11. External Communications..................................................................................21 4.12. Operational Acceptance and Project Closeout...................................................21 Appendix A – Project Management References ........................................................22 Appendix B – Work Breakdown (to Work Package Only) ......................................25 Appendix C – Core Management Structure ..............................................................26



1. Introduction

1.1. Document Purpose This Project Management Plan (PMP) is the prime management document to support the delivery phase of the Otahuhu Diversity Project (ODP). It references or contains all information required to manage the project. The three main sections cover:

• WHAT is to be done including project background, scope, requirements and objectives.

• WHO is to do it including project governance, organisation, resources, roles, responsibilities and communication.

• HOW it is to be done encompassing project plans, processes and systems for planning, monitoring and management through to operational acceptance.

The PMP facilitates project participant and key stakeholder understanding of project management requirements in order to help achieve project objectives. It will be updated as appropriate during the life of the project to reflect significant changes in scope, personnel, responsibilities or processes. However, it is anticipated that this Version 2 PMP will require no further updates.

1.2. Audience This version of the PMP is written primarily for project participants from Transpower plus the three main vendors being Maunsell, Transfield and AREVA. All project participants engaged by these four companies with any management responsibility for the project should read and comply with the PMP in order to support their project roles. Other project participants should also read the PMP (or parts of it) and associated management documents in order to help them understand the project and execute their project tasks as required. The ODP is a relatively large, complex and long duration project that will have many people working on it. The PMP is accordingly also a key document for project familiarisation for new project participants.

1.3. PMP Content and Associated Documents This Version 2 status PMP has been prepared when all major project participants have been engaged and management plans, processes and systems have been implemented. Accordingly almost all project management detail is documented elsewhere and the focus of this version of the PMP is to identify; reference and provide an overview of, and context for, these documents. Accordingly, where there is a primary source document such as a deliverable from the previous ODP phase of work (e.g. the Solutions Study Report) or a project procedure then the PMP contains relevant summary level information for clarity but references the relevant document rather than duplicating detailed information. This Project Management Plan should be read in conjunction with the contracts, plans and procedure documents that define the detailed processes that underpin its implementation. In addition there are several other documents that are relevant as background information.



Project specific management documents are identified in Appendix A with latest revision date (where applicable), owner and an outline of their content/purpose. They are referenced from the PMP text using the ‘Ref’ number. All project management documents listed in Appendix A are stored on the Transpower or Transfield project SharePoint sites.



2. Project Background, Scope & Requirements

2.1. Background Transpower has recognised an issue with the reliability of transmission through the existing 220 kV Otahuhu substation. Most of the power supplied into the upper North Island, including Auckland and Northland, flows through Otahuhu substation, and its reliability is of critical importance to these areas. Furthermore, a major failure at Otahuhu could credibly result in voltage collapse that would affect most of the North Island from Whakamaru northwards, and possibly further south. Transpower’s Otahuhu substation is a legacy asset, having been developed incrementally over the past 50 years. Although there have been a number of security upgrades over the years, such as the addition of bus zone protection and bus coupler circuit breakers to help mitigate the impact of failures, it remains a basic single-breaker double-bus design, that is not considered under good electrical industry practice to be appropriate for the level of power being transferred through the substation. Some of the historical developments have resulted in transmission lines crossing over both the 110 kV and 220 kV switchyards at the substation. These ‘over crossings’ are not unusual in an ‘industry practice’ context but are considered to be undesirable from the perspective of a critical substation because of the risk posed by falling conductors – a rare but high consequence event. Recent events at Otahuhu have highlighted the vulnerability of the existing switchyard to low probability, high consequence events. Although by definition, these events are rare, they are also highly unpredictable and can have a major impact on supplies to consumers. In the probabilistic planning context, it is not always feasible to enumerate each and every event that could lead to a high impact event. The probability of a high impact event is thus always higher than an enumerated approach to reliability assessment. Transpower’s Otahuhu Diversity Project will address the vulnerability issues and improve the reliability of the 220 kV Otahuhu substation by building a new 220 kV switchgear facility on the same site, but physically and geographically separated from the existing switchyard. Existing and new circuit connections will be diversified between the two switchyards so that a major failure in one of the switchyards will not result in a total loss of supply via Otahuhu substations. The flexibility offered by two independent substations will also improve the flexibility and operational options available to restore supplies in the event of major loss of load event. Other documents including the Solutions Study Report (Appendix A ref 1.1) and Application for Approval to the Electricity Commission (ref 1.2) provide more detail on project background.

2.2. Scope of Work Deliverables from the previous ‘development’ phase project included: • An awarded GIS/AIS/EHV Cable Design/Build (DB1) Contract covering most of the new

substation construction works • Conceptual design for ‘enabling works’ including new GIS/AIS platform, transmission line

deviation and associated infrastructure/services work • Resource consents and property acquisition and agreements • Electricity Commission and Transpower approvals to proceed with project delivery An outline of the scope of this ‘delivery’ phase project is: • Establish contracts for design and construction of the enabling works



• Execute the enabling works design and construction including provision of a new switchyard platform for the GIS/AIS construction and associated work plus existing bus and line protection upgrades etc

• Design and construction of new GIS and AIS facilities plus EHV cabling through the awarded DB1 contract.

• Commissioning and handover of the new facilities It is noted that there was some overlap of the development and delivery phases above (particularly award of the DB1 contract) but they were managed separately. The scope of work for delivery is described in detail in the Solution Studies report (ref 1.1) and fully specified in the contract documents (ref 3.1 to 3.5).

2.3. Business Case and Project Approvals The business case for the Otahuhu Diversity Project delivery (ODP) in the form of a ‘Grid Upgrade Proposal’ (ref 1.1) was developed and submitted to the Electricity Commission in 2006. The Electricity Commission approved the proposal in August 2007. The Transpower Board approved the project in September 2007 (ref 1.3) The CEO approved the Project Approval Document (PAD) in October 2007 (ref 1.4)

2.4. Project Work Breakdown Structure The Project Work Breakdown Structure (WBS) subdivides the project scope into increasingly smaller and more detailed ‘manageable chunks’ of work following a hierarchical structure. This is the common basis for ongoing integrated planning and management of scope, schedule, cost and resources across the project.

The WBS is developed and presented to three levels only in the PMP being:

• Level 1 – Project: Total scope of the ODP Delivery phase as defined in this PMP • Level 2 – Workstream: Five workstreams aligning with responsibility for project execution

being: Management/Support

Enabling Works Design

Procurement

Enabling Works Construction

GIS/AIS EHV Cable Design/Build

• Level 3 – Work Package: Breakdown to specific Work Packages within each Workstream being the cost/schedule integration level which is a summary task in the project schedule and the level at which where overall budgets are identified, forecasts are maintained and actual costs recorded (i.e. CA level project account in FMIS). WBS to work package level is shown in Appendix B.

Further WBS development through greater levels of detail is carried out as the project progresses as part of the ongoing planning and scheduling process.



2.5. Project Schedule Approved commissioning date for the project following Electricity Commission project approval was set as March 2010. Detailed schedules have been developed accordingly and current internal project target commissioning date is 26 February 2010. However, award of the DB1 contract slipped by 2 months to May 2008 and this has put significant pressure on the commissioning date. It is considered to be feasible but it includes no specific schedule contingency and given the complexity, concurrent parallel near critical paths, dependence on outage availability and risks associated with the project it is considered that the risk of slippage is high. Integrated detailed project schedules including identification of inter-schedule dependencies across all workstreams were developed and baselined as at 1/8/08 (following award of the DB1 contract and its initial planning). These are updated on a monthly cycle as described in 4.2 below and specified in the Scheduling Procedure (ref 5.1). See the summary Gantt chart and milestone schedules in current Monthly Progress Report or Steering Committee report (as identified in 4.1 below) for the baseline and latest actual/forecast dates.

2.6. Project Budget Regulatory approval has been received by Transpower from the Electricity Commission for up to $99M being the P90 estimate in the ‘Application for Approval’ (ref 1.2).

The Transpower Board approved a budget of $83M in September 2007 (ref 1.3) being the P50 estimate in 2006 dollars in the ‘Application for Approval’.

It is noted that the ‘mean project cost estimate’ in June 2009 dollars in the ‘Application for Approval’ is $94M.

The PAD budget as approved by the Transpower Chief Executive in October 2007 (ref 1.4) is $76.611M.

The project budget, as detailed in the PAD, has been mapped to the project work breakdown structure (see 2.4 above) at Work Package level and can be seen in the project cost status reports.

Commitments, forecasts and actuals are maintained and reported by work package along with budget and rolled up to workstream and total project level.

Refer to 4.3 below on how project costs are managed and reported as the project proceeds.

2.7. Contractual Approach The major ‘GIS/AIS and EHV Cable’ package of work has been established as a design/build contract with engagement of AREVA through competitive tendering under the previous ‘development’ phase of the project.

However, the Enabling Works contractual approach was driven by project time constraints which required construction to commence in January 2008 in order to meet target commissioning date but project approval was not confirmed until October 2007. This did not allow time for a traditional detailed design then construction tendering process. A faster competitive RFP process based upon existing conceptual design only was selected.

A construction contract was awarded in December 2007 with detailed design and construction proceeding in parallel. This is described in the Enabling Works Construction PMP (ref 3.4) and the associated ‘Scope Refinement’ process and associated cost management is specified in the EW Cost Management Procedure (ref 5.2)



2.8. Dependencies The project is largely independent of other Transpower projects except for the risk of unavailability of outages (or their cancellation) caused by other works or power system conditions. This has potential for significant schedule and some cost impact. It is managed by advance planning and early submission of outage requests plus close liaison with the System Operator.

There are, however, significant dependencies on other parties including: • Local authorities for resource and building consents • Contact Energy as owner of neighbouring power station (refer 2.1) • Other utilities including Vector, Telecom, Watercare and Manukau Water for relocation of their

services to accommodate the works.

These external dependencies are managed under the project scheduling process described in 4.2 below with associated communications with the parties managed as described in 4.11.

There are also many internal project dependencies between the 4 project major participants. Planning and management of these is a principal objective of the Project Scheduling Procedure (ref 5.1).

2.9. Key Delivery Objectives The following are key objectives of all project participants in delivery of the project:

• Most importantly; undertake the work safely – measured by achievement of safety KPIs

• No unplanned Loss of Supply (LOS) as a consequence of project work

• Delivery of specified project scope within the approved timeframes and budget.

• Management processes developed and applied to support efficient and effective execution of the work

• Open and honest communications between the parties with no hidden agendas. This includes sharing of information unless there is a clear commercial imperative for confidentiality

• A collaborative team approach by all project participants with communication and relationships between all parties conducted in a non-adversarial manner.

• Transparent management and appropriate escalation of issues at all levels of the project as and when they arise.



3. Project Participants, Governance & Organisation

3.1. Project Participants The four principal organisations responsible for project delivery and outline of their responsibilities are as follows. • Transpower New Zealand Ltd (Transpower) – Transpower is the Principal/Employer

responsible for overall management and delivery of the project.

• Maunsell AECOM Ltd (Maunsell) – Design consultant responsible for enabling works design and general technical support. See design contracts (ref 31, 3.2 and 3.3) for specifics.

• Transfield Services Ltd (Transfield) – Contractor responsible for enabling works construction. See EW construction contract (ref 3.4) for specifics.

• AREVA T&D Australia Ltd (AREVA) – Contractor responsible for GIS/AIS and EHV cable works. See Design/Build contract (ref 3.5) for specifics.

Several other subcontractors, vendors and consultants are also (or will be) employed on the project but are always engaged directly by one of the four companies above.

3.2. Project Organisation Structure The high level project organisation structure identifying only those core project team members with management responsibilities (i.e. role and appointee as at October 2008) is shown in Appendix C. Other people working on the project will do so under the direction of one of those named on the organisation chart. Specific roles and responsibilities of project team members are defined in the other referenced management documents and are not repeated here. More detailed organisation structures for specific aspects of the project showing other project team members are included in: • Transfield Enabling Works Project Management Plan (ref 4.5) shows the Transfield project

organisation structure • AREVA Project Quality Plan (ref 4.11) shows the AREVA project organisation structure • Maunsell Project Plans (ref 4.2, 4.3 and 4.4) shows the Maunsell project organisation structure

for each contract • Communications and Record Management Procedure (ref 5.4) includes the Transpower technical

management structure

3.3. Project Steering Committee The Project Steering Committee (PSC) provides executive overview and direction of the project and is a forum for escalation of issues from the project team.

Membership comprises senior management from the four principal organisations with others attending (see Appendix C). It meets 2 monthly or as required and is chaired by the Transpower Director, Capital Works Programme Group.

The PSC Terms of Reference document (ref 4.1 ) specifies PSC structure, purpose and role.

3.4. Enabling Works Management Team The Enabling Works Management Team (see Appendix C) provides management and coordination of the enabling works design and construction.



Core team members are: • Engineer to Contract (Chair) • Transpower Project Manager • Engineer’s Representative • Transfield Project Leader • Transfield Construction Managers • Maunsell Project Manager Other Transfield and Maunsell team members attend as required depending upon focus of work at the time. Meetings are held fortnightly on site. See the Enabling Works Construction PMP (ref 4.5) for more information.

3.5. DB1 Contract Management Team The DB1 Management Team (see Appendix C) provides management and coordination of the GIS/AIS and EHV cable works design and construction. Core team members are: • Engineer to Contract (Chair) • Transpower Project Manager • Transpower Technical Manager • Engineer’s Representative • AREVA Project Manager • AREVA Project Engineer • AREVA Site Manager Other AREVA team members attend as required depending upon focus of work at the time. Meetings are held monthly at Transpower’s Auckland offices or on site.

3.6. Project Communication Establishment workshops have been held for the Enabling Works and DB1 contracts immediately following their award to establish contract specific management objectives including responsibilities, processes, key drivers, KPIs and core values.

The Steering Committee, Enabling Works Management Team and DB1 Management Team as in 3.3, 3.4 and 3.5 above are the main ongoing forums for project communication and management for the remaining duration of the project. The overlap of membership between these teams is shown in Appendix C. The Transpower Project Manager and Engineer to Contract being the common link between all three forums.

Other forums are (or will be) established according to need including:

• Project Coordination – Meets monthly to identify and coordinate interdependencies between main project participants (Transpower, Maunsell, Transfield and AREVA). Attendees are combined Enabling Works and DB1 management teams as in 3.4 and 3.5 above and it is chaired by Engineer to Contract. Includes review of current integrated project schedule and input to next schedule update. Focus is on medium to longer term planning.



• Site Coordination – Meets weekly and complements Project Coordination meeting focusing on site ‘real time’ and short term issues. Chaired by Engineer’s Representative.

• Enabling Works Site Technical – Meets weekly or as required to address real time site coordination and technical issues. Chaired by Engineer’s Representative and includes Transfield and Maunsell.

• Enabling Works Protection - Meets weekly or as required for design and construction liaison on enabling works protection issues. Includes Engineer’s Representative, Transfield and Maunsell.

• Contact Energy Liaison – Meets monthly or as required to manage issues with Contact Energy as neighbours. Chaired by Transpower Project Manager and includes Transfield and/or AREVA and others as applicable

• DB1 Design – Transpower Technical Manager meets with AREVA as required for design input, review and approval of GIS/AIS and EHV cable works design and construction.

• Site Safety Coordination – Meetings will be held weekly between Transfield, AREVA and Transpower when AREVA commences work on site. Focus is on safety management and particularly coordination between Transfield and AREVA.

• Risk Workshops – Convened monthly or as required for both DB1 and enabling works to review open risks and identify new ones. Refer 4.9 below.

Refer to 4.10 and 4.11 below and the communications procedures (ref 5.4 and 5.3) which cover specific implementation of project communications and associated records management.

3.7. Project Stakeholders Stakeholders are those who are, or will be, affected in some way by the project. This does not include the project participants and project team members working to deliver the project. The project is also dependent upon some stakeholders as owners of external dependencies as in 2.8 above.

While not directly involved in ongoing project execution from a governance perspective, stakeholders must be kept informed in their area of interest and many stakeholders will have significant input to the project as it progresses.

Primary stakeholders include the following groups:

Transpower Internal • Board • Executive • Grid PMO • Asset Owner • System Operator • Inventory and Procurement (i.e. neighbouring Otahuhu Warehouse significantly impacted)

External • Electricity Commission – as regulator • Contact Energy - as neighbour owning Otahuhu Power Station • Vector Electricity Networks – supplied from substation and cable relocation works required • Auckland Regional Council – RMA role • Manukau City Council – RMA and building permit roles • Watercare Services – modifications to their trunk sewer required



• Telecom – infrastructure relocation works required • Major Energy Users Group (MEUG) – as project opponents Stakeholder communication is an integral part of the project scope to ensure that stakeholders are informed about the project. The Transpower Project Manager has primary responsibility for stakeholder communication. A formal stakeholder communications plan for the project has not been prepared at this stage but may be if it is considered that it would add value.



4. Project Management Processes

This section of PMP identifies and outlines the project management processes and procedures that prescribe how the project will be delivered by the project team. Detailed process/procedure information is not included in the PMP but they are listed in Appendix A5 and referenced from this section accordingly.

Transpower and Grid PMO standard processes, procedures and systems are used to support project management supplemented by project specific processes/systems as applicable.

Where project processes are not explicitly defined project management activities will be carried out following Project Management Institute best practice as defined in the standard ANSI/PMI 99-001-2004 ‘A Guide to the Project Management Body of Knowledge’.

4.1. Project Progress Reporting

Project progress reporting requirements are summarized in the table below.

Report Author Frequency Audience Contents

Enabling Works Construction Progress Status

Transfield Project Leader

Weekly

Prior to Management Team Meeting

EW Management Team.

Reviewed at EW Management Team Meeting

Ref 4.5

Enabling Works Construction Progress Summary Status

Transfield Project Manager

Monthly Transpower Project Manager

Input to Transpower monthly status report

Ref 4.5

Enabling Works Design Progress Summary Status

Maunsell Project Manager

Monthly Transpower Project Manager


Bullet point summary of tasks achieved last period, planned next period and open issues.

DB1 Works Construction Progress Status

AREVA Site Manager

Weekly Transpower PM, ETC and Engineer’s Rep

Ref 4.11

DB1 Works Progress Status

AREVA Project Manager

Monthly DB1 Management Team.

Reviewed at DB1 Management Team Meeting and input to Transpower monthly status report

Ref 4.11

Cost Status ETC Monthly Transpower PM


S curve and tabular output of monthly cost forecast (ref 5.10)

Summary Schedule ETC Monthly Transpower PM 1 page summary Gantt



Report Author Frequency Audience Contents


chart (ref 5.1)

Transpower Project Progress Status Report

Transpower Project Manager

Monthly Transpower management and posted on intranet

As per Grid PMO requirements

Steering Committee Report

Transpower PM with input from all project participants

2 Monthly Project Steering Committee

Reviewed at PSC meetings

As specified in PSC TOR (ref 4.1)

Key Performance Indices (KPIs)

ETC with input from Transfield and AREVA

2 Monthly Project Steering Committee

Reviewed at PSC and management meetings

KPIs including performance on safety, schedule, meeting attendance and action processing, query processing, drawing quality, risk management.

4.2. Scheduling Project scheduling is carried out as specified in the Scheduling Procedure (ref 5.1).

This procedure defines the process for initial development and ongoing maintenance of Otahuhu Diversity Project schedules.

Its objective is to ensure that all project work is appropriately planned and scheduled in order to: • align with and validate specified overall project timeframes • provide the basis for assigning and executing the work • support resource planning • accommodate external dependencies • identify and maintain inter schedule dependencies across the project • identify and provide early warning of schedule related variances or issues • report overall project progress at detailed and summary levels

Four ‘Level 2’ schedules based upon responsibility are developed and maintained covering full project scope and aligning with project WBS. These are as follows with owners and scope as outlined:

1. Transpower - owned by Transpower and covering Transpower work including procurement, technical review, RMA, property and general project management

2. Enabling Works Design - owned by Maunsell and covering the three enabling works design contracts

3. Enabling Works Construction - owned by Transfield and covering the enabling works construction contract

4. GIS/AIS/EHV Cable - owned by AREVA and covering all GIS, AIS and EHV cable works as in the DB1 contract.

They are maintained separately but integrated each reporting cycle into a single baselined, schedule for overall project monitoring and management reporting.

These ‘Level 2’ schedules are broken down to tasks of generally 10 days duration or less for the short term planning horizon. However, schedules may be progressively developed during project



execution with longer term work beyond about 2 months from the current date at a coarser level of detail (i.e. a ‘rolling wave’ approach).

Resources may be assigned to these ‘Level 2’ schedules or at a more detailed ‘Level 3’ that rolls up to ‘Level 2’.

A key requirement in maintaining the integrated schedule for the project is to ensure alignment between individual schedules. This is achieved by defining inter schedule links using specifically identified milestones and monitoring alignment of those milestones as described in the Scheduling Procedure.

Integrated schedule progress updating and reporting is normally on a monthly cycle with individual schedules updated more frequently as required.

Update approach is based upon maintaining current actual and best estimate of forecast future dates by task monitored against an approved baseline.

4.3. Cost Management Project cost management includes ongoing forecasting and recording of actuals and commitments by Work Package, monitoring against budget, reporting of variances and initiation of corrective action as applicable.

Its objective is to ensure that effective project cost control is implemented such that: • the best estimate of Forecast End Cost (FEC) for the project is maintained for each Work Package

and the total project on an ongoing basis • potential cost variances are identified early so that corrective action may be taken • expected variances of FEC from approved budget are identified, recorded and tracked • only legitimate ODP costs are charged to the project • project commitments are properly established and identified • cost status is reported according to Transpower requirements, clearly, accurately and in

appropriate detail to all levels of management • cost information is readily available to support specific investigations or requests • sufficient records are maintained in order to allow audit of all aspects of project cost history

Systems used are FMIS and MMS in accordance with Transpower business requirements (mainly for payment processing and recording actuals and commitments) supplemented by project specific systems for forecasting and reporting.

The project cost control cycle is monthly with updated commitments, forecast and actuals reported as at the end of each calendar month. Management summary reports include:

• Summary Cost Status – Tabular report with one line per Workstream including original PAD budget, current budget, forecast, commitments and actuals. This includes contingency amounts and derived variances

• Financial Year Summary – Tabular report showing actual and forecast expenditure by Workstream by financial year.

• Work Package Cost Status - Tabular report with one line per Work Package (approx 90) including original PAD budget, current budget, forecast, commitments and actuals plus variances.

• S Curve Summary – Graphical XY presentation showing cumulative costs by month plotting

o Current Approved Budget

o Commitments to Date

o Actual Cost to Date and Forecast to Complete



Overall project cost management is carried out using the Project Cost Control workbook (ref 5.10) as described in the Process sheet of the workbook .

Cost management requirements of the major contracts are defined in the contract documents according to their specific nature and requirements and are implemented as follows:

• Enabling Works Design – A Design Cost Register workbook (ref 5.7) is maintained to manage change submissions and approvals and payment applications and approvals prior to processing in Transpower’s MMS system.

• Enabling Works Construction – The ‘Scope Refinement’ process as specified in the EW Cost Management procedure (ref 5.2) is used to manage the concurrent design and build approach for this contract. An EW Cost Management workbook (ref 5.8) is maintained to record change submissions (i.e. Scope Refinements and Variations) and approvals and payment applications and approvals prior to processing in Transpower’s MMS system.

• AIS/GIS/EHV Cable Design/Build - Variations and payments are managed in accordance with the standard FIDIC General Conditions used for this contract. A Cost Management workbook (ref 5.9) has been developed to record variations, payment applications and approvals.

Also see Section 4.6 Change Management below.

4.4. Quality Management

The three prime vendors (Maunsell, Transfield and AREVA) are all ISO9001 accredited and have quality management systems in place accordingly. They have project specific Project Quality Plan documents for the Otahuhu Diversity Project. Quality management is accordingly the primary responsibility of the individual prime vendors for their deliverables. This is specified in their contracts. Transpower under the direction of the Technical Manager also reviews, carries out spot checks, provides feedback on and approves deliverables. This does not, however, constitute any transfer of responsibility for quality of delivery from the vendor to Transpower. Transpower may also require independent peer review of design work in critical areas – particularly protection design. Transpower may arrange external audit of vendor’s quality systems if required. This has been considered by the Project Steering Committee and the consensus view was that each vendor’s regular internal audit processes should be adequate and Transpower initiated external audit would only be undertaken if a specific need was identified. Transpower is not ISO9001 accredited but Transpower managed work will be undertaken in accordance with Transpower processes and be subject to audit.

4.5. Procurement Management Procurement management covers Transpower management of all externally procured services, works, materials and equipment. This includes:

• Enabling Works Design Services – Maunsell have been engaged as one of Transpower’s ‘preferred consultants’ under contract conditions TP/ServPC. The Transpower Project Manager is responsible for managing this work as specified in the contracts (ref 3.1, 3.2, 3.3).



• Enabling Works Construction – Transfield have been engaged through a competitive RFP process as one of Transpower’s ‘preferred contractors’ under contract conditions TP/Wks4G. The Engineer to Contract and Transpower Project Manager are responsible for managing this work as specified in the contract (ref 3.4).

• Enabling Works Equipment and Materials – Transpower’s Inventory & Procurement Group are responsible for procurement of primary equipment, secondary equipment, transmission line materials and other materials specified as required in the enabling works design.

• AIS/GIS/EHV Cable Design/Build - AREVA have been engaged through a competitive tendering process under FIDIC contract conditions for design services, equipment/material supply and construction works. The Engineer to Contract and Transpower Project Manager are responsible for managing this work as specified in the contract (ref 3.5).

The Transpower Project Manager and ETC supported by the Engineer’s Representative have primary responsibility for procurement management in accordance with the contracts and Transpower processes.

Transpower Contract Support Group is available to provide procurement management support and as at October 2008 have nominated Chris Mayo to this role as single point of contact for advice on contractual issues or provision of support.

4.6. Change Management Change management includes both ‘overall project’ and ‘contract specific’ scope change.

‘Overall project’ scope is well defined and few changes are expected on this project. The Project Manager is responsible for identifying any prospective changes or clarifications to approved project scope and submitting to Transpower management for approval.

Project scope changes are identified and tracked in the Project Cost Control work book (ref 5.10) and a separate scope change register is not maintained.

‘Contract specific’ scope changes, on the other hand, will be common. Change management processes for these are specified in the individual contracts and supporting systems for managing these changes have been developed as follows:

• Enabling Works Design – The Maunsell design contracts (ref 3.1, 3.2 and 3.3) are a mixture of ‘Time and Materials’ and ‘Fixed Price’. Scope Changes are initiated and processed as specified in the contracts and approved in accordance with Transpower delegations. The Design Cost Register workbook (ref 5.7) is used to record, reference and track all enabling works design scope changes.

• Enabling Works Construction – The nature of the Transfield construction contract being awarded without a detailed design and the associated ‘Scope Refinement’ process means that there will be a large number of changes which must be efficiently and effectively managed. Transfield manage a Design/Contract Query process which helps clarify scope and identify changes. The change management process is specified in the Enabling Works Cost Management procedure (ref 5.2) and the Enabling Works Construction Register workbook (ref 5.8) is maintained to record, reference and track all enabling works change submissions and approvals.

• AIS/GIS/EHV Cable Design/Build – The AREVA contract is a conventional fixed price contract with changes (Contract Variations) managed in accordance with the standard FIDIC General Conditions used for this contract. The DB1 Cost Register (ref 5.9) is used to record, reference and track all DB1 contract design scope changes.



4.7. Deliverables Management Project deliverables are managed in accordance with provisions of the relevant contracts and Transpower processes. This covers their initial specification, review, feedback, approval, signoff and handover.

Deliverables cover the following categories with Transpower approval as noted:

• Management documents including Project Quality Plans, Procedures, Management Plans etc are reviewed and approved by the Project Manager or ETC

• Technical documents including drawings, designs, technical specifications, test reports etc are reviewed and approved by the Technical Manager

• The physical works are reviewed and approved by the ETC supported by the Engineer’s Representative and ultimately the Asset Owner at project handover.

• Operating documentation, training material and training delivery are approved by the ETC with input from the Asset Owner

Design deliverables are listed in the DB1 Document Tree (ref 5.11) maintained by AREVA and the Enabling Works Drawings Log (ref 5.12) maintained by Maunsell.

4.8. Safety Management Safe execution of the works is the top priority project objective hence planning and management of safety is paramount.

This is specifically covered in the Enabling Works Safety Plan (ref 4.7), the DB1 Works Site Management Plan (ref 4.8) and the DB1 Works Health and Safety Emergency Plan (ref 4.9).

The nature of the works and site with two principal contractors and multiple subcontractors operating concurrently in the same general areas make safety management a significant challenge. This demarcation issue and clear definition of responsibility must be specifically addressed in the safety plans and ongoing safety management.

Safety is a standard agenda item for all three management forums.

Transpower will undertake regular site safety audits as part its safety audit programme and as directed by the Transpower Project Manager.

4.9. Risk & Issue Management Project risk management is carried out in accordance with Australian and New Zealand Standard for Risk Management (AS/NZS 4360).

Its objective is to ensure that all project risk is appropriately identified, assessed and managed. The process includes:

• Systematically identifying each risk • Assigning an owner to each risk who is responsible for monitoring and managing the risk • Evaluating ‘Likelihood’ and ‘Consequences’ to derive a ‘Level of Risk’ • Establishing ‘Treatment’ plans in response to each risk according to ‘Level of Risk’ to:

o reduce likelihood or risk event and/or o mitigate its impact should it occur

• Monitoring the application of risk treatment plans to ensure risk is being managed appropriately

• Recording the above on a ‘Risk Register’ to support management and monitoring.

Two Risk Registers are maintained as follows:



• Enabling Works – The enabling works risk register (ref 5.5) is managed by Transfield as owner of most (but not all) enabling works risks. The risk management process is specified in the Enabling Works Project Management Plan (ref 4.5). Some enabling works risks are owned by Maunsell and Transpower team members who have access to update the register on the Transfield team site.

• DB1 Contract Works – The DB1 contract risk register (ref 5.6) is managed by AREVA as owner of most (but not all) DB1 contract risks. Some DB1 contract risks are owned by Transpower team members and the register is accordingly held on the Transpower project SharePoint site so that both AREVA and Transpower have direct access to update it.

Risk management for both enabling works and DB1 contract include: • Risk registers in same format for consistency of presentation • Each risk reviewed and updated at least monthly • Risk management as a standard agenda item at management meetings • Specific risk review meetings – generally monthly • Reporting of all ‘Extreme’ and ‘High’ open risks to the Project Steering Committee who review

them as a standard agenda item at their meetings

Issues are identified and managed through the management and/or technical meetings as applicable, recorded as actions and escalated if required to the Project Steering Committee. A specific process and ‘Issues Register’ has not been set up to support Issues Management but may be in future if considered beneficial.

4.10. Communications and Records Management Project communications and records management is carried as specified in the Project Communications and Records Management procedure (ref 5.4).

This procedure defines how the four major project participants (i.e. Transpower, AREVA, Transfield and Maunsell) formally communicate and how the project records that are generated are managed.

Its objective is to provide the basis for effective communication and to ensure that appropriate records are prepared, stored and are readily accessible in order to support efficient execution of the project.

The procedure should be read in conjunction with project procedure ODP03 ‘Enabling Works Documentation Management and Communications’ (ref 5.3) which covers the detail of enabling works communications. Principles adopted for communications and records management include the following:

• Minimize administrative overhead consistent with meeting communications and records management objectives

• Formal communication between parties is to be by emailed ‘transmittal’ • Subject line of all transmittal emails must start with a unique transmittal ID in order to support

subsequent identification and retrieval • ‘Correspondence Logs’ listing all transmittals will be maintained and made available to both

parties of each transmittal • Where practical have single sources of common project records maintained by one party with

access by other project participants (i.e. minimize duplicate records held by different project participants)

• Processes should minimize the need to produce printed outputs of records • Authorization/approval normally is by email – hand written signatures are not required • Formal project records are stored in electronic form (no reliance on paper records)



• Standard forms should be used where beneficial but otherwise communications may be directly in the body of emails (not form for forms sake)

Tools and systems used to realize the principles above include: • A Transfield hosted ‘team site’ is the principle repository for enabling works construction

project records including Transfield maintained correspondence logs, drawings, meeting minutes, progress reports, risk register, schedules etc

• Transpower project development SharePoint site was for the planning and development phase of the project. It is now closed but contains a number of documents for reference including investigations, the Solution Study Report and those associated with establishing the execution contracts.

• A Transpower project delivery SharePoint site is for Transpower owned project records and those shared with or submitted by Maunsell and AREVA. This is structured to align with the overall project Work Breakdown Structure.

• Transpower email repository is for storage/retrieval of all transmittals plus emails in response to transmittals and any other emails that the sender considers should be held as a project record.

• Email and uploading/downloading records to/from the Transpower SharePoint site are the means for formal communication and the transfer of records. Where records are transferred via the SharePoint site then that transfer is communicated and referenced by email transmittal.

4.11. External Communications The Transpower Project Manager has primary responsibility for management of communications with stakeholders external to the project team (i.e. both internal and external to Transpower)

This includes determining: • Who to communicate with (i.e. stakeholder organisation and person) • What information to provide • How to communicate • When to communicate • Who should communicate (i.e. may be escalated or delegated from Project Manager)

Stakeholders to communicate with include the 14 identified in Section 3.7.

A specific external communications plan has not been developed for the project as communications requirements for each stakeholder are already established or sufficiently clear.

4.12. Operational Acceptance and Project Closeout Operational acceptance of the new assets by the Asset Owner will be in accordance with standard Transpower processes.

A ‘Project Closeout Report’ will be prepared including index of project records, lessons learned and list of outstanding project related tasks with identification of responsibility and timing for their completion.

Project participants are responsible for keeping records as the project proceeds for input to the Closeout Report. An ongoing ‘lessons learned’ register has not been set up for the project at this stage but will be if considered necessary to properly capture this information.



Appendix A – Project Management References Project specific management documents are identified below with latest revision date (where applicable), owner and an outline of their content/purpose. They are referenced from the PMP text using the ‘Ref’ number. Ref Document Date Owner Outline

1 Pre Delivery Phase Documents

1.1 Solutions Study Report 8/07 Transpower Detailed report on engineering investigations to establish scope of works for project to provide diversity at Otahuhu substation. Prepared by Maunsell. Original issue was 10/06.

1.2 Otahuhu Substation Diversity Project, Proposal, Application for Approval

12/06 Transpower This is Transpower’s ‘Grid Upgrade Proposal’ to the Electricity Commission advocating approval of the Otahuhu Diversity Project

1.3 Submission to Transpower Board for Project Approval

8/07 Transpower Board Paper recommending approval to delegate authority to the CEO to proceed with the works.

1.4 Project Approval Document (PAD)

9/07 Transpower Submission to CEO to approve proceeding with ‘Delivery’ phase of the project.

2 Environmental & Property etc

2.1 Contact Energy Agreement 12/07 Transpower Agreement between Transpower and Contact to ensure Transpower can carry out the project works and Contact can continue operation of the adjacent power stations

2.2 Land Use Resource Consent

11/07 Transpower Manukau City Council consent for the works

2.3 Stormwater and Industrial Trade Processes Consent

2/08 Transpower Auckland Regional Council consent including stormwater discharge and sediment control

3 Contract Documents

3.1 Enabling Works Detailed Design Contract (Civil)

9/07 Transpower/ Maunsell

Design contract with Maunsell for initial enabling works associated with AIS/GIS platform construction. Includes general civil infrastructure and transmission line deviations.

3.2 GIS/AIS Substation Tie-Line and Line Protection Detailed Design


Protection design contract with Maunsell for work new GIS /AIS works to be installed by the DB1 contractor

3.3 Enabling Works Protection, SCADA and Communications Detailed Design Contract


Design contract with Maunsell for balance of enabling works including protection, SCADA and communications.

3.4 Enabling Works Construction Contract

12/07 Transpower/ Transfield

Contract with Transfield for construction of enabling works

3.5 GIS/AIS/EHV Cable Design/Build Contract (i.e. ‘DB1’ Contract)

5/08 Transpower/ AREVA

Contract with AREVA for design, procurement and installation of the GIS/AIS/EHV cable and associated works.



Ref Document Date Owner Outline

4 Plans

4.1 Project Steering Committee Terms of Reference

5/08 Transpower/ Maunsell/ Transfield/ AREVA

Includes roles, responsibilities and membership of Project Steering Committee

4.2 Enabling Works Detailed Design (Civil) Project Plan

9/07 Maunsell Project Plan as per Maunsells Quality System for the contract

4.3 GIS/AIS Substation Tie-Line and Line Protection Detailed Design Project Plan


4.4 Enabling Works Protection, SCADA and Communications Detailed Design Project Plan


4.5 Enabling Works Construction Project Management Plan

10/08 Transfield Describes specific systems adopted by Transfield to comply with the requirements of the Enabling Works contract

4.6 Enabling Works Environmental Management Plan

8/08 Transfield Covers enabling works requirements in order to comply with the resource consents??

4.7 Enabling Works Safety Plan

4/08 Transfield Details the safety precautions and processes for Transfield and their subcontractors.

4.8 DB1 Works Site Management Plan

11/08 AREVA Define project specific procedures, practices, resources and responsibilities to ensure control of site and occupational health and safety of all personnel.

4.9 DB1 Works Health and Safety Emergency Plan

9/08 AREVA Methodology to respond to an emergency situation identified as per Environment Health and Safety emergency planning and preparedness procedure

4.10 DB1 Works Environmental Management Plan

9/08 AREVA To identify environmental hazards associated with the site and define management practices to minimise hazards in accordance with the contract and legislation

4.11 DB1 Works Project Quality Plan

10/08 AREVA Sets out specific quality practices for the DB1 works in accordance with AREVA quality system and AS/NZS 9001

5 Procedures/Processes/Registers/Systems

5.1 ODP01 – Scheduling Procedure

9/08 Transpower Specifies the process for initial development and ongoing maintenance of all Otahuhu Diversity Project schedules including their integration.

5.2 ODP02 – Enabling Works Construction Cost Management Procedure

3/08 Transpower/ Transfield

Defines the process by which Transpower and Transfield are to manage contract costs on the the Enabling Works contract. This includes ongoing management of change (through Scope Refinements and Variations), processing of



Ref Document Date Owner Outline payments and forecasting

5.3 ODP03 – Enabling Works Documentation Management and Communications Procedure

2/08 Transfield Covers specific documentation and communication requirements between Transfield and Transpower. Supplements ODP04 below.

5.4 ODP04 – Communications and Records Management Procedure

10/08 Transpower Defines how the four major project participants (i.e. Transpower, AREVA, Transfield and Maunsell) formally communicate and how the project records that are generated are managed

5.5 Enabling Works Risk Register

NA Transfield Risk register for enabling works in accordance with AS/NZS 4360. Updated monthly minimum.

5.6 DB1 Risk Register NA AREVA Risk register for DB1 works in accordance with AS/NZS 4360. Updated monthly minimum.

5.7 Enabling Works Design Cost Register

NA Transpower/ Maunsell

Workbook for recording, tracking, monitoring and approving design contract changes and payments. Includes process documentation. Updated on monthly cycle.

5.8 Enabling Works Construction Cost Register

NA Transpower/ Transfield

Workbook for recording, tracking, monitoring and approving enabling works contract construction changes (scope refinements and variations) and payments. Updated on monthly cycle. Process is specified in procedure ODP02 above (ref 5.2).

5.9 DB1 Cost Register NA Transpower/AREVA

Workbook for recording, tracking, monitoring and approving DB1 contract variations and payments as per the FIDIC contract conditions. Includes process flow chart. Updated on monthly cycle.

5.10 Project Cost Control Workbook

NA Transpower Workbook for ongoing cost forecasting at workpackage level, tracking changes, integration with actuals and commitments from FMIS and reporting. Updated monthly as at month end.

5.11 DB1 Document Tree NA AREVA Register of DB1 document deliverables including design reports, technical specifications and drawings. Updated on ongoing basis including delivery status.

5.12 Enabling Works Drawings Log

NA Maunsell Register of enabling works drawing deliverables. Updated on ongoing basis including delivery status.




Appendix B – Work Breakdown (to Work Package Only)

ID Workstream ID Work Package10 Management/Support 10_10 Project Management

10_20 Transpower Technical Support10_30 External Technical Support10_40 Environmental10_50 Property10_60 Switching & RTU/SCADA10_70 OTA Warehouse Changes10_90 Contingency

20 Enabling Works Design 20_01 110 kV Tie Line Deviation20_02 OTA - PEN C Deviation20_03 Warehouse Relocation/Alteration20_04 Manhole and Contact Sewer Relocation20_05 Site Platform Formation and Stormwater Relocation20_06 220 kV Switchyard Extensions20_07 220 kV Bus Zone Protection Modifications20_08 220 kV Protection System20_09 Cable Transition Stations20_10 Communications20_11 SCADA20_12 Local Service Power Supplies20_13 Security System20_14 Station Lighting20_15 Earthgrid Connections20_16 Sewerage Connection20_17 Water Supply20_18 Roading20_19 Vector Cable Relocation20_20 Miscellaneous Site Works20_21 Cable Route Security20_22 Low Impedance BZ Prot Existing 220 kV AIS20_23 Prot Settings Existing BZ20_24 Prot Settings Existing AIS

30

40 E

50

20_25 Prot Settings GIS20_26 Prot Settings Low Impedance BZ Existing AIS20_30 Tie Line and Line Protection20_90 Contingency

Procurement 30_01 Miscellaneous30_02 Primary Equipment30_03 Protection30_04 SCADA30_05 Secondary Equipment30_06 Communications30_07 Line Materials30_90 Contingency

nabling Works Construction 40_01 110 kV Tie Line Deviation40_02 OTA - PEN C Deviation40_03 220 kV Bay Tie Line 440_04 Tie Line 5 Cable Termination40_05 Southdown Cable Termination40_06 OTA 'C' Bus Tie Cable Termination40_07 220 kV Bus Sections 478 & 48840_08 Henderson Circuit Transition Station40_09 Southdown Circuit Transition Station40_10 Huntly Circuit 2 Transition Station40_11 Ohinewai (WKM3) Circuit Transition Station40_12 OTA 'C' Bus Tie Transition Station40_13 Earthing Connections40_14 General Civil Works40_15 Communications/Protection Signalling40_16 Protection Systems40_17 SCADA Systems40_18 AC Supply40_19 Water Supply40_20 Huntly Circuit 1 Relocation to Bay 50240_29 Project Management40_30 Vector Cable Relocation40_90 Contingency

GIS/AIS EHV Cable Design Build 50_01 MS1 Contract Agreement50_02 MS2 Plant & Bldg Design & Spec50_03 MS3 Factory Test Reports50_04 MS4 Civil Works50_05 MS5 AIS Substation Plant50_06 MS6 GIS Substation Plant50_07 MS7 220 kV Cables & Accessories50_08 MS8 Substation Installation50_09 MS9 220 kV Cables Installation50_10 MS10 O&M Manuals & Training50_11 MS11 Taking Over Certificate50_12 MS12 Contract Closeout50_13 MS13 Tests After Commissioning50_14 Cable Test Set50_15 Variations50_90 Contingency

Project Management Plan

Appendix C – Core Management Structure

Project ManagerJitesh Raniga

Engineer to ContractGraeme Oakden

Technical ManagerMalcolm Stewart

Engineers RepGarry Wright

Operations ManagerMohan Somasi

Project ManagerAnil Asija

TranspowerAREVA

Site ManagerBarnie Bezuidenhout

Project EngineerAlistair Williams

Reporting Communication

Director, CWPG Mark McKenzie

Northern Prjcts MgrBob Coombes

Project ManagerKevin Morris

Maunsell Transfield

Executive GMRoger Foy

Project LeaderColin Kemp

Construction MgrPaul Shotter

Construction MgrMarcus Levermore

Project DirectorAnant Prakash

DB1 Management TeamEnabling Works Management Team

Steering Committee

Steering Committee Members

Steering Committee Attendees


OTAHUHU DIVERSITY PROJECT EW COST MANAGEMENT PROCEDURE

Version: 1.1

Date Approved: 26/03/08

Appendix C ODP02 EW Cost Management Procedure v1_1.doc Page 1 of 17

PROCEDURE: ENABLING WORKS CONSTRUCTION COST MANAGEMENT

Procedure Ref No: ODP02

Version: 1.1


Owner

Graeme Oakden

STATUS APPROVED

EFFECTIVE FROM:

March 2008

DOCUMENT HISTORY

Version Description Author Date

1.0 Revised as per 19/2/08 cost management meeting

Graeme Oakden 21/02/08

1.1 Add appendix on Scope Refinement and Variation mgmt plus minor changes

Graeme Oakden 26/03/08

TABLE OF CONTENTS

1. Purpose ........................................................................................................................ 2

2. Overview ..................................................................................................................... 2

3. Responsibilities ........................................................................................................... 3

4. Inputs ........................................................................................................................... 3

5. References ................................................................................................................... 3

6. Outputs ........................................................................................................................ 3

7. Procedure .................................................................................................................... 4

8. Flow Chart .................................................................................................................. 8

Appendix A – Scope Refinement and Variation Management


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1. Purpose This procedure defines the process by which Transpower (TP) and Transfield (TSL) are to manage contract costs on the Otahuhu Diversity Project Enabling Works contract. This includes ongoing management of change (through Scope Refinements and Variations), processing of payments and forecasting.

Its objectives are to:

Support efficient and effective contract cost management

Streamline administrative and approval processes including minimizing of paper records through email based submission and approvals

Generate records to provide a full audit trail of both change and payment approvals

Provide clear and easily identified links back to prime documents as a record of reasons for changes

Meet Transpower’s requirements for cost management using the MMS and FMIS systems

Maintain a current record of actual expenditure, current approval and forecast by price schedule item that reconciles with summary figures in MMS/FMIS

Clearly report contract cost status versus original contract price at detailed and summary levels

2. Overview A key driver in establishing the cost management process for this contract is the need to accommodate the parallel development of design during the contract period and the associated ongoing ‘Scope Refinement’ during the construction period. A consequence is that there will be a relatively large number of changes to be managed under this procedure.

In the overall project work breakdown structure the Enabling Works Contract is one of six ‘Workstreams’. Next level down is ‘Work Package’ being the 21 summary items in the pricing schedule followed by each of the approx 400 items in the contract price schedule at the next level. In order to minimize administrative effort the Transpower MMS and FMIS systems are setup to capture costs and commitments at Work Package level only with supporting detail at price schedule item level maintained in the TSL cost system.

This procedure covers the entire TP/TSL process on ‘what’ is required but not the detail on ‘how’ to do it. The


Version: 1.1



‘how’ is covered in Appendix A and other material as referenced.

Timings stated in the procedure are based upon meeting MMS requirements for payment processing.

The procedure steps are based around the level of transfer of responsibility between TSL and TP only. Within each step TSL and TP may have a number of secondary steps (eg TP approval involves ETC (GO) recommendation to TP then TP (JR or higher) approval then ETC (GO) transmittal to TSL of that approval)

3. Responsibilities Roles and responsibilities in the context of this procedure are as follows.

Transpower – Responsible for initial setup of the contract in MMS, initiation of changes, review and approval of changes, review and approval of payments and processing of changes and payments in MMS.

Transfield – Responsible for developing and maintaining the system to support the process at price schedule item detail, submission of changes and submission of payments including MMS processing.

4. Inputs Enabling Works Contract

MMS Requirements

5. References Enabling Works Project Management Plan

TSL Contract Cost System ( ie spreadsheet plus instructions for users)

MMS User Requirements

FMIS User Requirements

6. Outputs Scope Refinements

Variations

Payments

Cost records and status reports


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7. Procedure

Step Action Who

1

Initial Setup

1.1 Setup Project in MMS

Enter the 21 ‘Work Packages’ (i.e. level 2 breakdown in price schedule) in MMS in accordance with MMS requirements.

TP

1.2 Setup Jobs in MMS

Enter ‘Job Requests’ in MMS with each Job linked to a single ‘Work Package’ being level 2 breakdown in the price schedule. It is noted that at initial set up 2 of the ‘Work Packages’ have 2 jobs each rather than 1 due to MMS constraints on approving values >$1.5M.

TSL

1.3 Complete Bidding in MMS

Complete standard MMS setup process being TP verification of Jobs, followed by TSL bidding prices as per the price schedule then TP approval.

TP/TSL/TP

1.4 Develop Cost Control System

Develop spreadsheet based system to support recording, tracking, submitting and reporting costs (including changes) in accordance with this procedure.

TSL

2

Changes

2.1. Initiate Change

Initiate a change via a ‘transmittal’ issued in accordance with the project communications procedure. This may be to issue a package of drawings (usually processed as a Scope Refinement) or other instruction (usually processed as a Variation) often in response to a Contract Query or Design Query.

TP


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Step Action Who

2.2. Prepare (or revise) and Submit Change

Determine price impact of change against current contract price by item as a ‘Scope Refinement’ or ‘Variation’ as appropriate and record in ‘Changes’ sheet of cost control system (refer Appendix A for details).

Include an aggregate summary of changes by MMS Job for each change submission (i.e. to become the ‘Work Orders’ submitted in MMS under step 2.5 below) and submit to TP by transmittal.

Note it is expected that TSL and TP will communicate informally on changes prior to submission to resolve issues and minimize the number of changes that are rejected in Step 2.3 and require revision under this step.

Keep record of justification of change value versus underlying ‘Estimator V6’ contract price detail for review and audit purposes (see 2.7 below).

TSL

2.3 Accept or Reject Change

Review, negotiate as necessary, recommend (GO to JR) and accept change (JR). This may necessitate a further cycle of Step 2.2 by TSL.

Advise acceptance or rejection by transmittal. (GO).

TP

2.4 Maintain Change Records

Update TSL cost system for accepted changes including status, amount and approval transmittal number.

TSL

2.5 Submit Changes as Work Orders in MMS Monthly

Submit new accepted changes as Work Orders in MMS from the accepted ’Changes’ sheet (i.e. at Work Package/MMS Job level) monthly no later than 10 working days before calendar month end.

TSL

2.6 Approve Changes/ Work Orders in MMS

Approve submitted changes/Work Orders in MMS checking that they align with those in the accepted ‘Changes’ sheet (JR) no later than 8 working days before month end in time for invoicing against those variations in that month.

TP


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Step Action Who

2.7 Spot Check Audit of Changes

Review and validate with TSL underlying detail of a sample of 3 to 5 changes per month.

Initiate corrective action as required.

Ratio of number requiring corrective action over total is a KPI reported to the Steering Committee.

TP

3

Invoicing/Payment

3.1 Prepare (or Revise) and Submit Claim for Payment

No later than 7 working days before calendar month end prepare a progress payment claim for the month by updating the ‘Payments’ sheet in the TSL cost system (refer Appendix A for information to be provide) for current claim amounts by item.

Include proposed claim summary by MMS Job/Work Order that balances with total claim by item and submit to TP by transmittal

Note it is expected that TSL and TP will communicate informally on progress status prior to submission to resolve any issues and minimize the number of claims rejected in Step 3.2 and require revision under this step.

TSL

3.2 Accept or Reject Payment Claim

Review, negotiate as necessary, recommend (GO to JR) and accept claim (JR). This may necessitate a further cycle of Step 3.1 by TSL.

Advise acceptance or rejection to TSL by transmittal (GO) no later than 4 working days before month end.

TP

3.3 Submit Payment Claims in MMS

Submit payment claims in MMS monthly as in the accepted ‘Payments’ sheet no later than 3 working days before month end as in the approved payment forms.

TSL

3.4 Approve Payment in MMS

Approve submitted payment in MMS checking that they align with the accepted ‘Payments’ sheet (JR) by the last working day of the month.

TP


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Step Action Who

3.5 Update Cost System & Post

Update TSL cost control system with current approved changes, payments and forecast by item as at month end and post on the project website by the 2nd working day of the month for access by TSL and TP.

TSL

3.6 Reconcile FMIS Payment Records with TSL System

Reconcile FMIS commitments and actuals by Work Package (i.e. CA Project) at each month end against Work Package totals from TSL cost system.

Follow up and arrange to fix any inconsistencies.

TP

3.7 Project Cost Forecasting

Incorporate TSL cost forecasts by work package into overall project cost forecast for month end reporting

TP


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8. Flow Chart

Se

tup

Ch

an

ge

s

1.3.Complete Bidding in

MMS

1.1 Setup Project in

MMS

TranspowerBoth Transfield

2.1 Initiate Change

2.2 Prepare (or Revise)

and Submit Change

2.3. Accept or Reject

Change

2.5 Submit Changes in

MMS

Pa

ym

en

t Mo

nth

ly

Responsibility

1.2 Setup Jobs in MMS

1.4 Develop Contract

Cost Control System

2.4 Maintain Change

Records

2.6 Approve Changes in

MMS

Rejected

Approved

3.1 Prepare (or Revise)

and Submit Claim

3.2. Accept or Reject

Payment Claim

3.3 Submit Payment

Claims in MMS3.4 Approve Payment

Claims in MMS

Rejected

Approved

3.5 Update Cost System &

Post on Project Website3.6 Reconcile FMIS with

TSL Cost Detail

3.7 Update Project Cost

Forecast

2.7 Spot Check Audit of

Changes


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APPENDIX A – SCOPE REFINEMENT & VARIATION MANAGEMENT

1. Objective

This Appendix specifies the process for ongoing identification and processing of Scope Refinements and Variations as defined in the Contract to support the Cost Management Procedure. The Principal, Contractor and Engineer to Contract have jointly developed a cost management process which includes:

1. Defining the initial Total Contract Sum for the contract and its breakdown into the various price schedule items and all related assumptions, rates, quantities and prices

2. A Scope Refinement process for managing the incorporation of the final (and approved) scope changes into the works and their effect (increase or decrease) on the Total Contract Sum

3. Variation management for managing the incorporation of changes into the works identified during the construction of the works and their effect (increase or decrease) on the Total Contract Sum

4. Measure and value activities where the Contractor carries out activities and is paid for the measured quantity at the agreed rate (items in the Price Schedule MV).

5. Pricing against provisional and cost reimbursable items

6. An ongoing updating process for the real time (as the contract progresses) cost management including regular updates of final contract forecast end cost to the Engineer and Principal

7. Closeout of contract and finalisation of all cost related matters

1.1 Collaboration

The parties agree that cost management for this contract will be undertaken in an open and transparent manner in accordance with the following guidelines:

1. The Contractor and Principal will endeavour to work together to solve any contract cost related matter.

2. The Contractor and Principal will notify the other party as soon as either becomes aware of any matter which could increase the Total Contract Sum.

3. The Principal, Contractor or Engineer may require the others to attend a meeting to discuss any early warning matter related to the contract cost

4. The Contractor will respond to any request for information made by the Principal or Engineer as soon as reasonably practicable. In any event the Contractor’s reply will be not later than 5 working days after the request


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5. The Engineer will respond to any request made by the Principal or Contractor for a response or decision as soon as is reasonably practicable. In any event the Engineer will provide a reply not later than 5 working days after the request

1.2 Role of the Engineer

The Engineer will facilitate the resolution of any matter between the Principal and Contractor. The Engineer will make a decision where the parties fail to reach agreement.

1. The role of the Engineer is as defined in clause 2 of TP/Wks 4

2. The Engineer will act impartially and fairly in all matters related to the contract and in particular cost (TP/Wks 4 GC 2.4)

3. Any decisions made by the Engineer will be in writing and provided to the Contractor and Principal (TP/Wks 4 GC 2.5)

4. The Contractor or Principal may dispute any decision or instruction made by the Engineer (TP/Wks 4 GC 2.6)

5. The Engineer may delegate any powers to the Engineer’s Representative (TP/Wks4 GC 2.2). Any delegations must be in writing and must be provided to the Contractor and Principal

6. The Contractor accepts that at times the Engineer will have two roles, one as Principal’s representative and the other as Engineer to Contract (ETC). If there is a conflict between these two roles the Engineer will retain the ETC role and request the Transpower Project Manager fulfil the Principal’s role.

2. References

1. Conditions of Contract TP/Wks 4 G/3 2. RFP Document Appendix 4 Specials Conditions of Contract Additional

Requirements for OTA-DIV-EW1

3. Definitions

Proposal Estimate The estimate based on detailed design documentation and information made available to the Contractor up to the time of Proposal submission. For each work element the level of accuracy/completeness of the scope is given by categories (ie ND, PD, SD and CD as defined in 4.1-2 below). The Proposal estimate forms the basis of the initial Total Contract Sum. Total Contract Sum The Proposal estimate prepared at award of contract as updated regularly throughout the contract period to include approved Scope Refinements and Variations.


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Contract Forecast Best estimate of final Total Contract Sum built up from current Total Contract Sum plus estimated variances including submitted unapproved and forecast Scope Refinements and Variations

4. Scope Refinement and Variation Management Process

Both parties agree the need to provide price surety to the Principal whilst not disadvantaging the Contractor. Outlined below is a cost change management process to achieve this outcome in an open and transparent manner.

4.1 Defining the Proposal Estimate

1. Transpower had prepared (as part of the RFP process) a Schedule of Prices which splits the (scope of) Works into:

a. Milestone items 1 and 2 (Project Management and Installation works respectively)

b. Work Package items (comprising the Project Management milestone as one Work Package and the Installation works subdivided into 20 Work Packages as identified in the contract price schedule)

c. Price schedule Items (break down of Work Packages to line items in the price schedule). For example item 2.6.5 or 2.7.5

d. Price Schedule Items are split by cost classification (Labour, Plant, Materials) and listed as either LS, MV, CR or PC:

- LS = Lump sum related for the work related to that defined / clarified within the notes

- MV = Measure and Value against a unit rate with clarification within the notes

- CR = Cost reimbursable with clarification within the notes

- PC = Provisional cost allowance with clarification within the notes

2. Transfield have completed the Schedule of Prices and have:

a. For the purposes of understanding the accuracy of the scope (and ultimately the accuracy of the pricing) the following categories are assigned to items in the Schedule of Prices:

ND = Not Defined

1. No similar or Transpower standard design information available

2. Estimate is based on high level information 3. Accuracy/Completeness of scope or design information <25%


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PD = Partially Defined 1. No similar or Transpower standard design information

available 2. Estimate is based on high level information including estimate

from subcontractors or other source of information 3. Accuracy/Completeness of scope or design information

25%<PD<60% SD = Substantially Defined

1. Similar or Transpower standard design information available 2. Estimate is based on information including estimate from

subcontractors or other source of information 3. Accuracy/Completeness of scope or design information

60%<SD<90% CD = Clearly Defined

1. Scope and design information to a detailed level 2. Similar or Transpower standard design information available 3. Accuracy/Completeness of design information

90%<CD<100%

b. Prepared the prices using information provided with the RFP documents and/ or their own assessment based on similar work activities undertaken for Transpower and/or Transpower standard designs, drawings and layouts. The reference/standard information has been indicated in the notes field of the “OTA-Enabling-wks-P-Schedule-Submission Rev_G.xls or in supporting correspondence

c. Prepared detailed Schedule of Quantities and related rates (Refer Transfield ‘Estimator V6’ Take off)

3. Transfield and Transpower agree that the totals for Milestones 1 and 2 plus

agreed price changes will become the Total Contract Sum for the scope of the Enabling Works (the Works).

4 An electronic copy and (hardcopy signed by the Principal and Contractor) of the

agreed Total Contract Sum and breakdown (to Transfield ‘Estimator V6’ level) will be made available to the Engineer and Principal in the event of dispute. This hardcopy will be initialled by both parties and be held in secure storage by the Contractor.

4.2 Scope Refinement

General comments

Scope refinement is the process whereby designs are issued and the price is refined based upon design drawings and specifications. This is the process of collaboratively working together to convert the ND, PD, SD and CD items into fixed and firm prices.


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Scope Refinement Process

1. As the design is finalised/approved by Transpower the information will be issued by the Engineer to the Contractor. Transpower will issue complete and comprehensive design documentation for work areas to allow meaningful assessment by the Contractor as described below

2. The design information will be provided to the Contractor (at least 5 working days or as detailed in Contract Programme/Schedule) before associated construction commences. Any change to the work element, will be assessed by the Contractor under the relevant categories:

a. No change to cost and / or time.

The approved design is as assumed / designed in the initial work element pricing. No change in cost or time results.

b. Change in scope

The approved design is different from the designed/assumed scope for the initial work element. The Contractor will prepare and submit proposed scope refinements including revised price with all necessary supporting cost information. The change may be an increase or decrease in price. The following basis of pricing will be utilised:

i. All rates, prices and quantities will be extracted from the initial Proposal Estimate including underlying detail.

ii. Where no directly applicable rates exist or the application of existing rates would be inequitable or unfair then new rates will be agreed

c. Significant change

The approved design is, in the Contractor’s opinion, a significant change or clarification from the design assumed / provided for the initial work element scope.

The Contractor will prepare and submit all necessary supporting time and cost/pricing information as in b) above and reasons why the change is “material”. Note: significant change can also relate to changes in quantum or nature of the particular works or change in design philosophy

3. The Engineer will review the submission, consulting with the Contractor and Principal before making any necessary changes and issue notification to the Contractor

4. Upon commencement of construction or procurement activities by the Contractor the method of cost change management will be as outlined in the Variation Management section described below.


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4.3 Variation Management. (Post construction start)

General comments

The implementation of the variation management process is generally utilised when changes to the scope of works occur during site construction activities or after related procurement activities have commenced.

Examples of when the Variation Management process applies may include:

A difference between the design drawings (upon which the scope refinement is based) and subsequent revised construction issue drawings

Site construction activities / conditions / circumstances necessitate a departure from the construction issue design

An instruction is issued by the Engineer to vary the works

1. The Contractor will assess the variation to the works under the relevant categories below:

a. No change to cost and / or time – The approved design as presented in the construction issue drawings is as assumed in the initial work element. No change in cost or time.

b. Variation Request –The Contractor is to prepare and submit proposed variations giving all necessary supporting time and cost information. Note the change may be an increase or decrease in price:

i. All price increases will use rates from the Agreed Labour Plant and Equipment rates and agreed Overheads and Profit (ie Dayworks rates).

ii. All price decreases will use rates prices and quantities extracted from the initial Contract Sum breakdown.

iii. Quantities will be extracted from the initial Contract Sum. (Transfield Estimator V6 takeoff)

iv. Where no directly applicable rates exist or the application of existing rates would be inequitable or unfair then new rates will be agreed.

2. Field work will proceed pending finalisation of any Variation Request and or price for the work element upon a notice to proceed being issued by the Engineer. The Contractor will gain the Engineer’s approval to bring onto site any additional resources, plant or equipment to complete any variation activity (such approval will not be unreasonably withheld)


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3. The Engineer will review the submission, consulting with the Contractor and Principal before making any necessary changes and issue notification to Contractor

4.4 Measure and Value Activities

Measurement of earthworks will be based on 3 topographical surveys to be conducted as follows:

1. Prior to commencement of Topsoil stripping

2. Prior to commencement of Bulk earthworks

3. On completion of earthworks

The difference between surfaces for surveys 2 and 3 will determine the volumes of cut and fill. This will also determine the cut to waste or imported fill requirement. All other measure and value items will be measured during execution of the work and/or upon completion as appropriate.

4.4.1 Explanation of 25% Quantity Variance

The Transfield proposal includes the statement “Please note that some rates may be affected by changes in quantity and >25% and Transfield reserve the right to review these rates for which a situation occurs”.

The clause above is based on reasoning given for clauses 9.3.5 and 9.3.6 in the guidelines for NZS 3910:2003 In summary this is to protect against an item reduced in quantity sufficient enough to lower the productivity therefore effectively increasing the overhead for that item.

The nomination of 25% is a blanket figure to flag significant changes to measure and value items. In actuality, they would be looked at on a case by case basis as reduction (or increase) in quantity may have varying degrees of effect (or none at all) depending on both the schedule item and degree of reduction

4.5 Cost Reimbursable and Provisional Costs

Where the Classification for the Work Element is Cost Reimbursable (CR) or is Provisional as noted in the price schedule the applicable rates will be based on the rates included in the Proposal Estimate. (ie not Dayworks). Where no directly applicable rates exist or the application of existing rates would be inequitable or unfair then new rates will be agreed

4.6 Records and Reporting

Transfield will maintain cost records and manage the updating and reporting process. The overall Construction Estimate will be recorded and maintained in an extended version of the Proposal Estimate (price) schedule spreadsheet. This will be developed to include:


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1. ‘Changes’ sheet identifying each Scope Refinement/Variation and including:

a. Initiating transmittal ID

b. Price schedule item number

c. Reason for Scope Refinement/Variation

d. Drawing number, revision, title and issue date (where applicable)

e. Variation/Price Refinement value including breakdown by labour, subcontract and materials

f. Date of submission

g. Approval status, date and approval transmittal ID

h. MMS Works Order number

i. Change category

j. Change summary by MMS Works Order package

2. ‘Payments’ sheet identifying each price schedule item and including:

a. Item ID

b. Description

c. Category (i.e. ND, PD, SD or CD)

d. Classification (i.e. LS, MV, CR or PC)

e. Unit, Quantity, Rate, Hours and prices as per Proposal price schedule

f. Notes as per Proposal price schedule

g. Approved value of Scope Refinements/Variations

h. Total approved price

i. Claimed last period

j. Claimed to last period

k. Claimed this period

l. Total claimed to date

m. Percent claimed to date

n. Total forecast cost

o. Subtotals by MMS Job/Work Package

p. MMS claim summary by Job and Works Order

This spreadsheet will form part of the “open set” of project documentation that will be accessible to the Engineer and the Principal. Transfield will maintain records of the underlying detail linked to quantities and rates in the ‘Estimator V6’ Proposal Estimate to support quantification of Scope Refinements and Variations for auditing by the Engineer under step 2.7 of the procedure.


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Transfield’s direct cost recording and documentation will be carried out in Transfield JDE/SAP accounting system At the completion of each of the Project phases 1, 2 and 3 (or other stages as agreed) the Contractor will closeout that portion of the Works and provide the Principal with a final end cost for the phase (ie section) of the Works.

4.7 Contract Closeout

The Contract closeout of the Contract from cost perspectives will be completed as quickly as reasonably practical after issue of the Take over Certificate for each phase/stage.

Commercial in Confidence

Transpower New Zealand Limited

Otahuhu Diversity Project Independent Quality Assurance Review

Health Check Review

Date: January 2009

Version: 0.6 draft

Transpower – Otahuhu Diversity Project IQA Health Check Review - Report

Commercial in Confidence Page 2 of 43

Executive Summary

Introduction IQANZ was requested by the Senior Risk Manager to provide an independent quality assurance Health Check Review of the Otahuhu Diversity Project as part of the 2008/09 Internal Audit Plan. KEMA Consulting has been engaged to address specific technical components. KEMA and IQANZ have not undertaken any previous reviews with respect to this project.

Project Background The purpose of the Otahuhu Substation Diversity Project (the project) is to diversify and improve the reliability of supply into Auckland and Northland through the Otahuhu substation.

Currently most of the power for the upper North Island including Auckland and Northland is supplied through the 220kV Otahuhu substation, and its reliability is of critical importance to these areas. Furthermore, a major failure at Otahuhu could result in voltage collapse that would affect most of the North Island from Whakamaru northwards, and possibly further south.

Recent events at Otahuhu have highlighted the vulnerability of the existing switchyard to low probability, high consequence events. Historical developments have resulted in transmission lines crossing over both the 110kv and 220kv switchyards which, while not unusual within industry practice, pose the risk of falling conductors. While a rare occurrence, they are a high consequence event with an example of such being the power outage which occurred in 2006 caused by the failure of an overhead earth wire crossing over the existing AIS switchyard.

The solution proposed by Transpower is to build a new 220kV switchgear facility on the same site, but physically and geographically separated from the existing switchyard, with new and existing circuit connections diversified between the two. This would mean a failure in one of the switchyards would not result in a total loss of supply via Otahuhu substations, and also improve flexibility and operational options to restore supplies in the event of the major loss of load.

The key delivery objectives of the project are specified within the Project Management Plan Version 2.0 (the PMP) as:

- Most importantly: undertake the work safely – measured by achievement of safety KPIs

- No unplanned Loss of Supply (LOS) as a consequence of project work

- Delivery of specified project scope within the approved timeframes and budget

- Management processes developed and applied to support efficient and effective execution of the work

- Open and honest communications between the parties with no hidden agendas. This includes sharing of information unless there is a clear commercial imperative for confidentiality.

- A collaborative team approach by all project participants with communication and relationships between all parties conducted in a non-adversarial manner.

- Transparent management and appropriate escalation of issues at all levels of the project as and when they arise.

The project is a committed investment project with a budget of $99M approved by the Electricity Commission, and with a planned commissioning date of 2010. The project is currently in the delivery phase.



Review Objectives The key objectives of this Health Check Review were:

• Determine whether the overall project management environment (governance, project management approach, processes, standards and controls) in place for project are appropriate, robust and in accordance with the Transpower’s approved policies and procedures, and prudent practice.

• Provide assurance to the Sponsor, Sponsor Delegate and the Transpower Board that the project is being managed in accordance with internal guidelines and that it is well positioned to deliver expected outcomes within time and budget, and to the expected level of quality.

• Determine whether technical aspects of the project have been adequately considered for a project of this nature (undertaken by KEMA).

• Identify project strengths and weaknesses, and provide appropriate and pragmatic options and recommendations for any opportunities for improvement with regard to the project management approach, processes and controls in order that the project meets Transpower’s project management requirements and prudent practice.

Conclusion In summary, this is a large and complex project that is being well run by an experienced and capable project team. Being a multi-vendor project on a live switchyard, the close monitoring of inter-dependent tasks and safety management is of paramount concern. Safety is a prime requirement from Transpower and has been dutifully followed by the project team with adequate safety and site management plans, an emphasis on safety on site, evidence that contractors are ‘walking the talk’, and regular coordination and site management meetings to ensure transparency of all tasks on site.

Whilst a safety incident did occur earlier this year which was not immediately reported to senior management, it is not clear whether this would have been reported outside the standard 24-hour notice period expected from Transpower’s contractors. However it is clear that safety is being provided the due attention it requires, and the vendors demonstrate a clear understanding that it is a number one Transpower priority.

A robust governance and management process has been put in place, utilising a Steering Committee of senior representatives from across the vendor organisations, to perform risk and issues management, as well as continue fostering the high level of cooperation that is evident across the project. While this is an effective means to ensure good communications across the vendors, it does mean some functions normally carried out by a Steering Committee cannot be done, such as monitoring delegated authority within the project, ensuring compliance with internal project management standards / quality, and guidance on vendor commercial issues and decisions, and ensuring adequate representation from the affected areas of the Transpower business. Instead this appears to be done between the line management functions of the Transpower Project Manager, Sponsor Delegate and Sponsor. We understand Transpower are establishing programme managers and a governance framework within the Grid Projects area, and are also considering forming a Governance Board. These roles could complement the project functions currently being considered by line management; in the interim, in the lack of any significant commercial vendor issues, the Steering Committee appears to be working well, although we would strongly suggest the addition to the Steering Committee of a representative from the Grid Performance division.

The need for civil works to commence before the scope and detailed drawings were fully defined, has led to the need for the development of an innovative scope refinement process to control costs and scope creep. A detailed pricing schedule was agreed within the Transfield and Maunsell contracts, with provisional estimates provided within the RFP responses for those work components that were only at conceptual design phase. As detailed drawings are completed by Maunsell, final costs can be ascertained under the scope refinement process. We understand the process is working well, with the final Maunsell costs tracking close to that originally forecasted, and Transpower satisfaction to date with the Transfield refined costs submitted. The success of this process is testament to the amount of planning to develop the procedure, and to the amount of trust established between Transpower and its preferred suppliers, Transfield and Maunsell, for the Enabling Works.



Bearing in mind that a number of innovative processes and procedures have been developed, we would suggest Transpower find some means for capturing and sharing these learning’s across the wider Transpower team. This is perhaps something the new Grid Programme Management Office could consider.

The vendors have all expressed a clear understanding of the contractual procedures in place, the scope management, escalation process, safety requirements and objectives of the project. We note that Areva is a relatively new supplier for performing works with Transpower in this area, and accordingly are being managed with a more ‘hands-on’ approach. Part of this has been a series of design workshops based in Sydney to bring them up to speed on Transpower’s design standards, expectations and requirements, and a clearly defined scope, detailed within their contract. We note that due to a two-month delay in completing contract negotiations with Areva and Areva securing subcontracting resource, the Areva schedule submitted to the project has no provision for contingency. Accordingly there is a high risk of slippage, although this is being monitored closely by the Engineer to Contract.

Minor improvements are possible for the project schedules, such as some task durations and linkages, but this is not unusual for a project of this size and complexity. Indeed, it is commendable that the right level of attention and detail to scheduling and dependency management is occurring, and the project should be encouraged to keep up the good work in this area.

A number of critical tasks have the potential to delay the project, such as the delay in manufacture and delivery of the 220kv cables, and relocation of the Contact sewer / stormwater pipe and other services. This is being monitored closely by the Engineer to Contract.

Risks are adequately captured in two risk registers maintained by Transfield for the Enabling Works (civil construction works, demolition and preparation of the switchyard platform), and by Areva for the DB1 works (the building of the enclosed GIS switchyard and cable troughs). The risk procedure has been developed on Australian / New Zealand risk standards. All risks expected for a project of this nature have been adequately captured, with only minor suggested improvements. We note that the management of risks is considered a prime function of the Steering Committee, and is appropriately dealt with at regular management level meetings.

It does appear that there is room for improvement for the level of engagement with the eventual Asset Owner of this project, being the Grid Performance division. While operational acceptance has been outlined within the Project Management Plan, we would expect further detail on how the operational impacts of the new asset are proposed to be managed, such as the handover of as-built standards, training, operational documentation, testing and commissioning, etc. This will become increasingly important as the project draws nearer to the commissioning date.

Review participants are satisfied that project deliverables delivered to date have been of high quality and the vendors are all ISO9000 accredited, with appropriate quality plans in place. However the discussion of quality within the project management plan is quite light. Bearing in mind this is an essential item for the project to minimise the risk of outages, and while we are satisfied there is a robust quality process in place for all project work, we feel it would be beneficial to have this outlined within one document (such as a quality management plan), or alternatively detailed in greater depth within the PMP. A programme of external / independent audits should also be a consideration for key milestone points.



Summary of Key Findings The review findings (strengths and opportunities for improvement) from this review are summarised in the following table. In order for readers to quickly identify the relative strengths and weaknesses of the project we have assigned an overall effectiveness rating to each review element. The following key describes these ratings:

Key Description

Effective controls / activities in place. No issues were identified.

Effective controls / activities, minor issues identified or some compensating controls exist.

Partially effective controls / activities in place. Moderate or low risk issues identified.

No effective controls / activities in place Or high risk issues were identified

Key Review Components Rating Key Findings

Summary

In summary, this is a large and complex project that is being run well. A robust governance, safety and management process has been established, along with a Steering Committee (a first for the Grid Projects division) comprising senior representatives from across the vendors, to perform risk and issues management and focus on safety, as well as continue fostering the high level of cooperation that is evident across the project, although it would be beneficial to include a representative from the Grid Performance division.

A robust scope refinement process has been established to control potential scope creep and cost control from the need for civil works to commence before the scope was fully defined. We understand the process is working well and is testament to the amount of trust established between Transpower and its preferred suppliers, Transfield and Maunsell, for the Enabling Works.

Minor areas for improvement exist within scheduling, the descriptions and mitigation treatments currently recorded for some risks, and the potential development of a quality management plan and external communications plan, and further involvement of the Grid Performance division with the project.

Additionally a number of critical tasks have the potential to delay the project, such as the delay in manufacture and delivery of the 220kv cables, and relocation of the Contact sewer / stormwater pipe. This is being monitored closely by the Engineer to Contract.

Governance & Management

• Project Team members have the appropriate level of experience and authority, with a clear demarcation of roles and responsibilities, and there is a high level of confidence and trust amongst them.

• The project utilises a Steering Committee (a first for the Grid Projects division) consisting of senior representatives from across the vendors for safety, risk and issues management, and as means of communication to continually foster cooperation across the project.

• The Sponsor and Sponsor Delegate is actively engaged and senior management have high visibility of the project.




• A good range of key performance indicators have been developed and are utilised appropriately by the project management team.

• Robust vendor and records management procedures are in place, with intranet sites and correspondence logs supporting strong version control for design drawings and other key project deliverables.

• Minor improvement opportunities exist within the project management plan and the Steering Committee terms of reference.

Scope

• For the Enabling Works, an innovative scope refinement process has been established to control potential scope creep and costs resulting from the need to commence civil works before the detailed drawings were complete. For the DB1 (i.e. construction of the enclosed GIS switchyard), the scope is comprehensively detailed within the Areva contract.

• For changes which are not scope refinements, there is an appropriate scope change management process and contract variation process which is managed by the Engineer to Contract, and includes the escalation of all scope changes impacting time, cost and quality to the Steering Committee for review and approval.

• Review participants clearly articulated an understanding of the approved project scope and objectives, and noted the project is maintaining a tight control in this area

Time / Schedule

• Currently tracking to plan in respect to meeting the commissioning date, although two months behind in awarding the DB1 / Areva contract and there is a high risk of slippage due to the lack of any contingency within the Areva schedule.

• A number of critical tasks have the potential to delay the project, such as the delay in manufacture and delivery of the 220kv cables, and relocation of the Contact sewer / stormwater pipe and other services. This is being monitored closely by the Engineer to Contract.

• Full critical path analysis is not currently possible due to some missing linkages within the Areva schedule, however the Engineer to Contract is working with Areva to resolve this. Additionally, consideration might be warranted on conducting sensitivity analysis on key tasks, to help manage stakeholder expectations and project scheduling.

• The project has established a robust scheduling process with fortnightly coordination meetings and ‘rolling wave’ approach to more detailed ‘level 3’ scheduling, which is entirely appropriate for a project of this complexity and should be commended.

• The project makes good use of milestone table and rolled up GANTT charts for progress reporting.

Cost / Budget

• The project has regulatory approval to spend up to $99M and has recently approved P90 board approval for delegation to the CEO of this amount. The project is currently forecasting spend of $97M.

• Detailed budgeting has been carried out to the work package level, and there are robust cost management and reporting procedures in place.




• Review participants noted the administrative complexity of having to use the Transpower Maintenance Management System (MMS) which is not really fit for purpose for use for projects of this size and complexity. For future projects, Transpower should consider alternatives for the financial management of project costs.

• Robust cost control procedures for scope refinements and contract variations are in place.

Resources

• Feedback from review participants confirms that resource levels are tracking to plan, with the requisite capability and capacity to deliver expected outcomes, within time and to the required level of quality.

• For the larger contracts of work, vendors have been engaged using the Transpower-modified FIDIC Yellow Book standards.

• Establishment workshops were held for the Enabling Works and DB1 contracts immediately following their award to establish contract specific management objectives including responsibilities, processes, key drivers, KPIs and core values, including safety.

• Key performance indicators are being used to monitor project team performance, safety and interactions between the two. (Such as design query response times).

• A strong degree of trust and cooperation has been established across all parties.

Safety

• The project has developed ‘safety’ KPI’s for the project, which are included within the monthly vendor status reports and monitored by the Project Manager, who has prime responsibility in this area.

• Safety procedures appear robust, with key documents have also been developed by both Areva and Transfield for safety and emergency plans, and environmental management planning.

• There is evidence that the contractors ‘walk the talk’ when it comes to safety.

• Minor improvements exist in terms of the management of SF6 gas, which while being a low risk hazard should be included in the appropriate safety / site management plans.

• There was a perceived failure to immediately report a safety incident earlier this year, however there was no evidence that this would not have been reported within the standard 24-hour reporting period during the normal course of events.

Risk & Issues Management

• Project risk management is carried out in accordance with the Australian and New Zealand Standard for Risk Management (AS/NZ 4360).

• Two risk registers are maintained – one orientated towards Enabling Works and which is maintained by Transfield on their project intranet site.

• Some minor improvements could be made within the risk registers in terms of the risk description and proposed mitigation strategy, and consistency within the risk ratings, and some missing risks detailed further within this report.

• Appropriate risk management and reporting is carried out by the project, with adequate discussion at Steering Committee level.



Integration

• There are a high level of interdependencies within the project which are managed through an interlink schedule, monthly coordination meetings, on site representation and management plans, and representation by senior representatives across all the vendors on the Steering Committee.

• More formal dependency tracking and management could be achieved through the development of a Dependencies Register.

• The project is reliant upon securing planned outages in order to proceed, which is highly subject to outside influences, for example, dry winter events.

• It is unclear as to what level of ongoing consultation is in place with the eventual Asset Owner, the Grid Performance division, and what steps are in place to minimise organisational impact upon this area. (E.g. Planned support arrangements, etc).

Communication

• The project uses a range of meetings across the parties, and review participants commented on a high level of transparency.

• Communication is a prime responsibility for the Transpower Project Manager, and status reports provided to management teams and the Steering Committee are clear and of high quality.

• Good use of sharepoint sites for version control and formal communication by way of email ‘transmittals’ which are registered within a correspondence log.

• Communications is being handled appropriately, but given the concerns over reputational risk and opposition by MEUG by the project, we would suggest the development of an external communications plan to formalise and plan these communications and maintain key messages.

Quality Management

• The vendors are all ISO9000 accredited and review participants report a high level of standards within the project deliverables.

• Evidence suggests an appropriate socialisation / consultation process with respect to key deliverables; with final approval points noted for all key deliverables and document within the project schedule and document controls. However we note the project may benefit from a separate quality management plan to provide guidance on quality management planning and to standardise quality management activities and clarify the standards expected.



Key Recommendations The following recommendations should be addressed as a high priority:

• Steering Committee Membership (high priority) (Recommendation 1.1)

Consider representation from the Grid Performance area (the eventual business owners) on the Steering Committee.

The following recommendations should be addressed as a medium priority:

• Peer Review the schedule (medium priority) (Recommendation 1.6)

Conduct a peer review of the project schedules focusing on design hold-points, tasks of long duration, logical linkages and any missing tasks, and a sensitivity analysis of the critical path.

• Organisational Impact Strategy Development (medium priority) (Recommendation 1.14)

Ensure adequate consultation, planning and documentation for impact on the Asset Owner, such as training and support procedures, transfer / acceptance of known issues, develop of ongoing maintenance contracts and procedures, etc.

• Develop A Quality Management Plan (medium priority) (Recommendation 1.18)

Consider developing a quality management plan to detail and incorporate all quality measures, such as the design drawings peer review approval process and the levels to which external independent peer review is expected (e.g. in-depth review against Transpower Standards).

• Consider the use of FMIS only and not MMS for Future Projects (medium priority) (Recommendation 1.8)

Consider the appropriateness or otherwise of FMIS only for use as a project cost and invoice control system rather than MMS.

Next Steps The project report will be finalised and presented to the Project Sponsor. IQANZ is happy to discuss the detail of this report and provide further explanation and advice with respect to the intention behind the recommendations contained in this report.



Management Comment Summary

Specific Actions on Key Recommendations:

Recommendation Priority Management Response (including action to be taken)

Date Action will be Completed

Steering Committee Membership (Recommendation 1.1)

Consider representation from the Grid Performance area (the eventual business owners) on the Steering Committee.

High Agreed. Invite Ian Burgwin (or delegate) to join Steering Committee from next meeting in March 2009.

Feb 2009

Peer Review the schedule (Recommendation 1.6)

Conduct a peer review of the project schedules focusing on design hold-points, tasks of long duration, logical linkages and any missing tasks, and a sensitivity analysis of the critical path.

Medium Agreed. This will be incorporated in the planned review of the detailed integrated schedule to be carried out in March/April 2009 as agreed at 10/12/08 Steering Committee Meeting (refer minutes item 7.4 and action 4.2). Prior to this ETC will brief the 4 schedule owners on audit recommendations as input to the February 2009 schedule updates that will be used as the basis for this review.

Apr 2009

Organisational Impact Strategy Development (Recommendation 1.14)

Ensure adequate consultation, planning and documentation for impact on the Asset Owner, such as training and support procedures, transfer / acceptance of known issues, develop of ongoing maintenance contracts and procedures, etc.

Medium Accepted. Detailed planning has not yet been carried out for this; however, it is covered at a high level in PMP 4.12 and general Transpower requirements/processes are well established. It is considered that the optimum time for detailed planning, preparation and implementation of ‘handover’ to the Asset Owner is from late 2009 to commissioning in March 2010.

Dec 2009

to

Mar 2010

Develop A Quality Management Plan (Recommendation 1.18)

Consider developing a quality management plan to detail and incorporate all quality measures, such as the design drawings peer review approval process and the levels to which external independent peer review is expected (e.g. in-depth review against Transpower Standards).

Medium Under consideration. AREVA, Transfield and Maunsell are all ISO9001 compliant and maintain the own quality plans accordingly. Transpower has established technical review processes with responsibilities as defined in the PMP for this project. It is not clear that a specific additional Quality Management Plan for the project will add value. The Project Manager will prepare a submission on the subject for consideration at the next Steering Committee meeting.

Mar 2009



Consider the use of FMIS only Instead of MMS for Future Projects (Recommendation 1.8)

Consider the appropriateness or otherwise of MMS for use as a project cost and invoice control system.

Medium Agreed. The requirement to use MMS for Enabling Works project payments adds significant administrative constraints, complexity and effort for little benefit to the project. The ETC and/or PM will brief the PMO for the benefit of future projects.

Mar 09



Table of Contents

Executive Summary .................................................................................................................................................... 2

Introduction ................................................................................................................................................................2

Project Background....................................................................................................................................................2

Review Objectives ......................................................................................................................................................3

Conclusion ..................................................................................................................................................................3

Summary of Key Findings..........................................................................................................................................5

Key Recommendations..............................................................................................................................................9

Next Steps ..................................................................................................................................................................9

Management Comment Summary ..........................................................................................................................10

Document Signoff .....................................................................................................................................................12

Document Control.....................................................................................................................................................14

Document Information.............................................................................................................................................14

Document History.....................................................................................................................................................14

Distribution Control ..................................................................................................................................................14

Associated Documents ............................................................................................................................................14

Background...............................................................................................................................................................15

Review Objectives ....................................................................................................................................................15

Review Scope ...........................................................................................................................................................15

Approach...................................................................................................................................................................16

Review Team ............................................................................................................................................................18

Detailed Findings and Recommendations..............................................................................................................19

Governance and Management................................................................................................................................19

Scope ........................................................................................................................................................................24

Time / Schedule.......................................................................................................................................................26

Cost / Budget ...........................................................................................................................................................28

Resources.................................................................................................................................................................29

Safety Management.................................................................................................................................................31

Risk & Issue Management ......................................................................................................................................33

Integration ................................................................................................................................................................36

Communication ........................................................................................................................................................38

Quality Management................................................................................................................................................40

Appendix A – Project Documentation.....................................................................................................................42

Appendix B – Project Team Management Structure .............................................................................................43



Document Control

Document Information Document Name: Transpower Otahuhu Diversity Project, IQA Health Check Review - Report

Contact Person: Justin Parker

Status: Draft

Document History Author Description of Change Date Version

Justin Parker Initial Document 12 December 2008 v0.1 draft

Justin Parker Update for Internal QA 15 December 2008 v0.2 draft

Justin Parker Update for feedback 15 December 2008 v0.3 draft

David Benfell Update for additional feedback 17 December 2008 v0.4 draft

Justin Parker Update for factual accuracy 16 January 2009 v0.5 draft

Wendy Edwards Update for Management Comments 29 January 2009 v0.6 draft

Distribution Control Person Role Date of Issue Version

David Benfell Engagement Lead 12 December 2008 v0.1 draft

Phillip Grieshaber KEMA Principal Consultant 12 December 2008 v0.1 draft

Wendy Edwards Senior Risk Manager 15 December 2008 v0.2 draft

Wendy Edwards Senior Risk Manager 17 December 2008 v0.4 draft

Mike Carter Project Sponsor 17 December 2008 v0.4 draft

Mark MacKenzie Project Sponsor Delegate 17 December 2008 v0.4 draft

Mike Carter Project Sponsor 16 January 2009 v0.5 draft

Wendy Edwards Senior Risk Manager 29 January 2009 v0.6 draft

Associated Documents Document Name Date of Issue Version

IQA Terms of Reference 4 Nov 2008 v1.0 final



Background

Review Objectives The key objectives of this Independent Quality Assurance Health Check Review were to:

• Determine whether the overall project management environment (governance, project management approach, processes, standards and controls) in place for project are appropriate, robust and in accordance with the Transpower’s approved policies and procedures, and prudent practice.

• Provide assurance to the Sponsor and the Transpower Board that the project is being managed in accordance with internal guidelines and that it is well positioned to deliver expected outcomes within time and budget, and to the expected level of quality.

• Determine whether technical aspects of the project have been adequately considered for a project of this nature (undertaken by KEMA).

• Identify project strengths and weaknesses, and provide appropriate and pragmatic options and recommendations for any opportunities for improvement with regard to the project management approach, processes and controls in order that the project meets Transpower’s project management requirements and prudent practice.

Review Scope The scope of the work for this review focused on the following areas:

In Scope Components

• Review of the current status of the project to gain an understanding of progress and context for reporting purposes.

• Review the project management environment including standards, processes and controls.

• Provide comment on the quality of the following:

− The processes to ensure appropriate governance and management of the project.

− The project’s monitoring and reporting processes and environment.

− The existing and proposed project management controls.

− The project’s objectives, success criteria and their definitions against the agreed project charter.

− The processes used to develop a clear definition of the total project scope, inclusions and exclusions.

− The project schedule and estimation processes.

− The project’s resourcing approach and its ability to manage those resources.

− The project’s approach to financial management; including budgets, approvals and reporting.

− The project’s approach to decision making and the major decisions made to date.

− The project’s approach to change management (business and technical) and the major changes managed to date.



In Scope Components − The project risks, mitigation strategies and management controls.

− The project’s approach to the management of its dependencies.

− The project’s communication management approach with internal and external stakeholders.

− The project’s quality assurance, audit and testing strategies and approaches.

• Provide comment on the following technical areas:

− Review of the technical aspects of the project to date.

− Review the technical risk (all levels) and advise on the appropriateness of the risk level, remedy and any other technical risks which may have been overlooked for a project of this scope.

− Review the potential effect on partially completed designs while construction is underway and comment on contingency aspects, communications, protection and the control building.

− Review the preparedness of Transpower for the significant testing and commissioning schedule.

− Review primary and secondary isolation techniques as applicable in a transmission substation, including a review of each contractor’s Site Safety Plan.

• Identification of findings (strengths and improvement opportunities) together with pragmatic recommendations in relation to any improvement opportunities.

• Preparation of a draft report for factual accuracy review by the Project Manager.

• Delivery of a final report for presentation to the Project Sponsor and Steering Committee.

The scope of this review excluded the following:

Scope Exclusions

• A review of the project feasibility study, business case and cost/benefit analysis.

• A review of the procurement process, ROI, RFP and resulting contracts.

• A technical review of the design and solution chosen.

• Any ICT or business operational processes.

Approach Our approach for this review was to:

• Review the project management documentation outlined in Appendix A – Project Documentation Checklist.

• Meet with the Engagement Sponsor to determine the key stakeholders to be interviewed as part of the review process. IQANZ conducted interviews with key stakeholders, who included:

1. Project Sponsor Delegate – Mark McKenzie

2. NI Projects Manager – Bob Coombes

3. Project Manager – Jitesh Raniga

4. Engineer to Contract – Graeme Oakden (Contractor)

5. Engineers Representative – Garry Wright (Beca)



6. Technical Manager – Malcolm Stewart

7. Transfield PSC Member – Roger Foy

8. Transfield Project Manager – Colin Kemp

9. Maunsell PSC Member – Anant Prakash

10. Maunsell Design Manager – Kevin Morris

11. Areva Project Manager – Anil Asija

• For the technical aspects of the review, KEMA conducted additional interviews with:

1. Engineer to Contract – Graeme Oakden

2. Technical Manager – Malcolm Stewart

3. Transfield Project Manager – Colin Kemp

4. Areva Project Manager – Anil Asija

• Meet with Mike Carter, GM and Patrick Strange, CEO, to discuss initial findings prior to drafting the report.

The following table outlines the roles and responsibilities and schedule of activities undertaken during this review.

Action Objective Resource

Preparation

Agree Quality Assurance requirements

Identify the specific quality assurance review requirements.

Familiarise IQANZ with Transpower’s ICT Governance Framework and Enterprise Project Management Methodology.

Familiarise IQANZ with the project background and context.

Engagement Sponsor IQANZ Practice Manager

Draft Terms of Reference Document review objectives, scope, approach, dates, interviewees and documentation to be reviewed.

IQANZ Practice Manager

Approve Terms of Reference

Review, approve and signoff the Terms of Reference.

Authorise commencement of the IQA process.

Engagement Sponsor Project Sponsor

Execution

Documentation Review Request project documentation.

Detailed review of project documentation.

Prepare file notes of key findings and recommendations.

Engagement Lead Senior Consultant

Conduct Interviews Conduct interviews with agreed stakeholders, covering project management control areas and specific questions arising from documentation review.

Key Stakeholders Engagement Lead Senior Consultant



Action Objective Resource

Initial Review Findings IQA review team workshop to review initial findings, highlight significant issues, ensure scope and objectives of review have been covered.

Draft initial findings and recommendations.


Draft Report Draft detailed findings and recommendations in regard to review.


Internal QA Review Ensure quality of report adheres to internal IQANZ standards, Terms of Reference and agreed quality measures.

IQANZ Practice Manager

Draft Report Presentation of the draft report to the Management Chair.


Management Chair

Completion

Finding Validation Review (Factual Accuracy)

Review draft report to ensure findings identified are factually accurate.

Management Chair

Final Report Present final report (hard and soft copy) to Project Sponsor.

Engagement Lead Project Sponsor

Review Team IQANZ assigned an experienced team of personnel to conduct this work. David Benfell led this engagement.

Team Member Role

David Benfell Engagement Lead

Justin Parker Senior Consultant

Phillip Grieshaber KEMA Principal Consultant



Detailed Findings and Recommendations

Governance and Management

Rating Effective controls / activities, minor issues identified or some compensating controls exist

Findings

Project Management Structure and Controls

The project is a relatively large, complex and long duration project, engaging multiple vendors on a live 220kV switchyard. The project is managed in two parts:

- Enabling Works: covers the provision of a new switchyard platform for the GIS / AIS construction and associated work, plus existing bus and line protection upgrades. Maunsell have been retained to perform the design works for the Enabling Works, with Transfield the prime for its implementation.

- DB1: covers the new GIS and AIS facilities plus EHV cabling, which includes the cable troughs and building of the substation. Areva are performing both the design and construction works for DB1.

The team structure is outlined in Appendix B – Project Team Management Structure, which has been taken from the Project Management Plan (PMP). The project follows the standard Transpower approach for Grid upgrade projects whereby an Engineer to Contract (ETC) works to a Project Manager from the Grid Projects division. The project manager in turn reports to his line manager, the Northern Projects Manager. Under this arrangement in addition to acting as the conduit for technical / engineering issues the ETC does a substantial amount of project management work, such as responsibility for project controls, setting up the project framework, managing the interfaces and the scope refinement process. Whereas the Project Manager appears to act at more of a project director level, split across a number of major projects, and with prime responsibility for finances, external communications and safety.

We note this approach appears to work well for this project, with review participants clear on roles and responsibilities.

We understand Transpower are currently reviewing this project approach in general, with a view to removing the ETC, introducing programme managers, and re-balancing the tasks into the current Project Manager role with support from the newly established programme management office (PMO). Transpower are also considering whether to establish a governance group to sit across all Grid projects. However, the Otahuhu Project will remain in its present form until completion.

The vendors have been engaged for the larger contracts using the Federation Internationale des Ingenieurs-Conseils (FIDIC) Yellow Book1 standards which have been further refined for Transpower’s needs. All other contracts follow Transpower's suite of contract conditions depending on contract value. For example, the Enabling Works construction contract with Transfield complies with Transpower standard "TP Works 4G3" conditions, which also sets out the deliverables.

Project management is through the PMP version 2.0 dated October 2008 (the PMP) and integrated project schedules, along with the measurement of a number of project KPI’s, including an emphasis on safety, and supporting project management plans from the vendors. Currently projects are expected to follow the ‘Capital Works Process’ which is effectively a project management framework, and the substantial range of design templates and Transpower construction policies, standards and requirements. In terms of PMP’s and other project deliverable templates, the project has used the best available at the time. However with the establishment of the

1 FIDIC Conditions of contract for Electrical and Mechanical Work.



PMO, it is expected that these templates and styles will be further refined and standardised across all Grid projects.

A review of the PMP for this project finds that it is a robust document with references to other documents to avoid duplication. While this is appropriate, we feel certain areas should be duplicated again within the document, such as the terms of reference for the Steering Group, and the roles and responsibilities of the core project team members.

The project is unique within the Grid projects area in that it has a Steering Committee, primarily established due to the need for the project to commence civil works before designs had been completed and to sit across subsequent risks, remove roadblocks and ensure open communication amongst all the parties. The Steering Committee consists of executive members of the prime vendors and Transpower, including the Sponsor Delegate.

The project is currently in the delivery phase.

Sponsor Delegate

The Sponsor Delegate, in his capacity as the Capital Works Programme Director, has the appropriate level of organisational oversight and authority to successfully sponsor the Project and has taken a detailed interest due to the reputational risks associated with the Otahuhu substation. He has substantial project management experience and is the driver behind the existing project changes within the Grid Projects area, including the establishment of the PMO. Examples of his detailed involvement have been a complete detailed review of the first scope refinement submitted by Transfield, and of the costings behind the first scope variation, aided by his background in cost engineering. He also chairs the Steering Committee. He has a particular interest in ensuring safety for the project.

The Sponsor Delegate has been involved with the project for circa 18 months.

Core Project Management Team

The project manager has been with Transpower for over six years, with experience in the Transpower projects pre-approval management unit before moving to the Northern Projects Team. Accordingly he has an excellent understanding of Transpower processes and is receiving a good level of mentoring / support from his line manager, the Northern Projects Manager. The project manager is currently working on three other projects and is primarily responsible for external communications and safety. He is based in Auckland and meets regularly with the Project Team, and co-locates to the site office 2-3 days each fortnight.

The Northern Projects Manager has a team of five project managers and is responsible for all grid upgrade projects north of Taupo. He effectively acts as part practice manager and part portfolio manager of the projects under his care. He meets weekly with his team to monitor progress and provide mentoring and support.

The ETC is an independent contractor, PMI certified and with extensive experience in Transpower projects. He is currently fully engaged on Transpower projects, working on this project and managing the business process reengineering stream within the Transpower Market Systems Project (MSP). The ETC runs a series of meetings with the DB1 and Enabling Works Management Teams, including progress meetings, risk workshops, and schedule coordination meetings. The ETC also manages the commercial aspects of the vendor arrangements, including the scope refinement and contract variation process, and has extensive experience in this area. Feedback to date is that the ETC has established a high level of engagement with the Steering Committee members, the project team and key stakeholders. He is based in Wellington and co-locates to the Otahuhu Site office 2-3 days each fortnight.

The ETC has an Engineers Rep based in Auckland for managing the onsite construction of the project, including resolving minor technical issues as they arise. The Engineers Rep is an employee from Edison, with extensive experience in Transpower projects. He is assigned 2-4 days per week on the project, ramping up or down dependent on the level of project activity. He is currently also engaged in overseeing another project at Otahuhu which is replacing some of the aged infrastructure on the existing switchyard.

Feedback from review participants indicates a high level of confidence in the experience and capability of the project management team, with particularly good feedback about the ETC’s experience, relationship skills and overall capabilities.



Management Teams

The construction work is split into two streams, DB1 and the Enabling Works. We note that both the DB1 and Enabling Works proposed management team structure and key personnel were thoroughly vetted for competencies and experience by the Transpower project team during the RFP process. Both Management Teams have the Transpower ETC, Engineers Rep and Project Manager on them, and are highly experienced and capable.

Transfield has established a construction office onsite, where the Transfield project management team is based. There is also ample room for the Core Project Management team, including specific desks for the ETC, Engineers Rep and Transpower Project Manager. Transfield also has a project facilitator assigned to the project whose duties include managing the Transfield’s Intranet site for the project. The Transfield Project Leader is the GM for Projects and Generation Group, and has over 30 years project experience. The Transfield project management and team structure is specified in the Transfield Enabling Works Project Management Plan.

The Areva Project Manager has extensive experience in electrical construction, and was originally a protection and control engineer. We note that while Areva have not had extensive experience on Transpower projects, this is mitigated by a more thoroughly detailed contract, their involvement on the Steering Committee, a more hands-on management approach from Transpower, and Transpower has given Areva access to their internal intranet site for Transpower design policies and standards. The Areva project management and team structure is specified in the Areva Project Quality Plan.

All vendors expressed a clear understanding of the contractual procedures in place, the scope management, escalation process, safety requirements and objectives of the project. Review participants commented there has been a commitment within Senior management across all vendors

Technical Management

A Technical Manager has been assigned to manage technical issues as they arise and for quality assurance of the design work. The Technical Manager has been with Transpower for over 18 years and is a Senior Development Engineer, with the ability to draw on technical expertise from the different groups across Transpower, as well as contracted resources / specialists as and when required for peer review and conducting the design work itself.

Checks and balances are achieved through a spot check of design changes by the ETC, although this is of limited value as the ETC does not have the same level of expertise. However, review participants noted that the Technical manager is highly competent and pragmatic in his design work.

Steering Committee

The Steering Committee consists of representatives from across Transpower and the three prime vendors at senior management level, with attendance by the four project managers, ETC, and the Technical Manager. This is an excellent way of ensuring a good flow of information between the vendors, issue escalation, buy-in from all parties, and brings a wealth of expertise to the group. However, we note that as Transfield and Areva are competitors there are restraints on what issues can be raised and dealt with at Steering Committee level, such as commercial issues (if any) with the vendors and concerns about vendor performance; and functions such as monitoring / ensuring delegated authorities within Transpower are being adhered to. We also note the absence of any representation from the Grid Performance division, which will be the eventual owner of the asset.

Steering Committee members interviewed articulate a consistent understanding of project scope and objectives; and involvement to-date shows clear accountability for undertaking their project governance responsibilities. Key duties of the Steering Committee include risk management, scheduling for planned outages, ensuring the project achieves critical success factors and to act as a forum for communication across the parties – although the Chair is careful to ensure this does not become an arena for aggrieved commercial claims.

A terms of reference for the Steering Committee has been established and agreed between members, although some minor areas have not been covered within it, (detailed within the recommendations below). Additionally, it is not apparent whether the Steering Committee has any delegated authority to act.

Steering Committee meetings are held on a regular basis and are provided adequate time for meetings (up to four hours), which are chaired by the Sponsor Delegate, with the ETC performing the secretariat function for these. Meetings are face-to-face. Feedback from review participants was that the Steering Committee is working well.

We were advised from participants that this is the first time a steering committee has been utilised for Grid Projects, which is a reflection of the size of the project, complexity and number of contractual interfaces involved. We understand Transpower are considering introducing Steering Committees for other projects of a similar size and scale.



Monitoring and Reporting

The Steering Committee receives a steering committee reporting pack three days in advance of Steering Committee meetings. The packs provide a comprehensive level of information along with key performance indicators (KPIs) and construction photos, the latter of which review participants have agreed have contributed to a good understanding of progress.

We understand that while the project has been formally approved by the Electricity Commission, there is no ongoing requirement to report on progress. Governance is provided through existing practice where project managers produce regular (currently monthly) project status and commentary reports to the line manager, who reports upwards in turn. These are picked up within the Divisional Reports to the CEO who reports to the Board on the project as required. These reports are also made available to the Grid PMO and others.

The Grid PMO also collates and analyses project status reports and provides summary status information to Transpower management for governance and higher-level reporting purposes on a monthly basis.

In summary, we find the project has established robust governance and management procedures, with senior management actively engaging in emphasising the need for cooperation amongst all parties. It was noted that while there is a good level of interest by senior management in the project, during major events on site such as planned outages, a senior management presence onsite to provide visibility of Transpower’s commitment would encourage further project team motivation. Additionally, regular positive feedback (where warranted) would also be beneficial, especially for team members where was work conducted during adverse conditions such as weather storms. A primary concern is the possible lack of involvement from the eventual Asset Owner in the project, and we would suggest as a minimum their representation on the Steering Committee.

# Recommendations Priority Owner Due Date

1.1 Steering Committee Membership – Asset Owner

Consider representation from the Grid Performance area (the eventual asset owners) on the Steering Committee.

High Sponsor Delegate Feb 2009

1.2 Steering Committee Reporting Packs

Consider extending issuing the reporting pack at least one week in advance of meetings, from the present three day period. Add to the agenda the approval of minutes from the previous Steering Committee meeting.

Low Project Manager (see comments re trade off for report quality if one week

lead time is agreed)

Completed

1.3 Project Management Plan

Consider adding:

- A summary of the Terms of Reference for the Steering Committee,

- Descriptions of the roles and responsibilities of the members of the project management team

- Commissioning and testing strategy, or reference to how this will be developed.

- Handover to BAU procedure, and development of supporting operational documents.

Low Project Manager Mar 2009



1.4 Steering Committee Terms of Reference

Consider adding sections on:

- The process where a Steering Committee member cannot attend (e.g. proxy vote? Post-briefing? How to advise non-attendance?)

- Decision making (e.g. Chair to have power to bring discussion to an end and determine a position)

- Recording of decisions. e.g. written resolution to be signed by all parties?

- Circulation of minutes. i.e. to be within 3-5 working days of a steering committee meeting

- A signature panel for each Steering Committee member’s signoff

Low Sponsor Delegate Mar 2009

1.5 Senior Management Visibility

Consider the onsite presence of senior management during major events such as during planned outages, so as to emphasise cooperation and motivate the project team.

Low Sponsor Feb 2009



Scope

Rating Effective controls / activities in place, no issues were identified

Findings

Scope Definition

The scope of the project is to build a new physically separate, enclosed, high reliability 220 kV switchyard on the Otahuhu site for diversification. The scope was documented within the Otahuhu Substation Diversity Project Grip Upgrade Plan Application for Approval (dated 4 December 2006) as:

• Construct a new 220 kV Gas Insulated Switchgear (GIS) facility adjacent to but physically separate from the existing 220 kV switchyard. This switchyard will be for the connection of incoming and outgoing circuits.

• Construct a new 220 kV air insulated switchgear facility adjacent to the new GIS building in single breaker double bus configuration. This switchyard will be for the connection of reactive plant and transformers.

• Connecting the existing switchyard to the new GIS switchyard by two cable tie lines.

• Re-arrange the existing 220 kV Henderson and Penrose outgoing lines and the 220 kV Huntly and Whakamaru incoming lines so that one circuit from each line will be connected to the new 220 kV GIS facility. Rearrangement of these key incoming and outgoing circuits will result in a split of circuits between the existing switchyard and new switchgear so that the loss of either facility will not result in a total loss of transmission capacity into Auckland and Northland.

• Construct a new control room for the two new switchyards. This will be geographically and electrically independent from the existing control room.

• Remove and cable existing 220 kV crossovers of the 110 kV bus.

• Install two bus section circuit breakers in the existing switchyard in order to improve its reliability.

A detailed Solutions Study Report developed by Maunsell in conjunction with Transpower (numbering some 177 pages) was completed in August 2007 which detailed the proposed design and scope of works. This was further built upon within an RFP and the resulting contracts that were developed with the vendors.

Deliverables from the previous development phase of the project included the RFP and awarding of the DB1 contract, the conceptual design for the enabling works, resource consents, property acquisition and agreements, and the requisite Electricity Commission and Transpower approvals to proceed with project delivery.

The scope of the delivery phase of the project is to establish contracts for the design and construction of the enabling works (now complete) and implement these works; develop the design and execute construction of the new GIS and AIS facilities through the DB1 contract, and the commissioning and handover of the new facilities.

Due to the construction window for the enabling works and to allow construction to commence in January 2008, it was decided to commence the civil works before the detailed design work was complete. Accordingly a construction contract was awarded in December 2007 with detailed design and construction proceeding in parallel, with the scope based on the work completed in the detailed solutions study. The size of the required platform and components were not given, instead vendors were asked to make assumptions (e.g. volume of concrete / steelwork required) and priced on this basis for the RFP (the provisional sum / estimate).

The design work for the Enabling Works has been scoped into three separate work packages, all of which has been awarded to Maunsell via a competitive RFP tendering process with clear milestone dates per design deliverable. The project also ensures a continuous flow of information between Transfield and Maunsell to ensure



design resources are directed to the requisite design components should re-prioritisation of delivery dates be required, such as to will allow time for adequate planning and resourcing by Transfield.

Monitoring and control is achieved through a detailed, integrated schedule with the vendors which is discussed every two weeks at project coordination meetings with the vendors run by the ETC. Design version control is managed by Transfield via a sharepoint system managed on their intranet. Risk is mitigated by the fact that both Maunsell and Transfield have done this type of work before, and as a preferred supplier are expected to understand Transpower’s required standards. We note this needs to be rigidly monitored and controlled to ensure focus is maintained on design inputs and delivery of the design drawings between the parties as required.

For the DB1 workstream, the contract is both a Design and Build contract. As Areva are somewhat new to being used by Transpower in this area, the scope has been comprehensively detailed within the contract, although review participants note Transpower are open to design refinements and suggestions. Further, current design workshops are underway with Areva to ensure understanding of Transpower’s existing design policies and standards that will help further clarify scope, coupled with a peer review function of the completed designs by the Technical Manager.

Review participants articulated a clear understanding of scope and of the project delivery objectives.

Scope Change Management

For the Enabling Works, the risk of scope creep and thereby costs was high in that the enabling works had to commence before the scope was fully defined. To reduce this risk, an innovative approach has been taken to pricing whereby for work that could not be clearly defined within the RFP, Transfield and Maunsell were required to develop a pricing schedule within their RFP response, with provisional estimates provided based on what was understood from the conceptual designs and the solution study. As the project progresses the scope and costs are further refined against the design drawings (as they are completed) from Maunsell as part of a ‘Scope Refinement’ process, against the rates in the pricing schedule. A detailed ‘Scope Refinement Process’ is prescribed within the Transfield Enabling Works Construction Contract, and an Enabling Works cost Management Procedure which was developed and agreed with Transfield.

Review participants note this process is working well. The ETC also notes that while they could have employed an independent quantity surveyor to double-check pricing, due to the transparency and maturity in Transfields pricing, only spot checks have been required by the ETC. The Sponsor Delegate was also involved in a detailed, line-by-line cost breakdown for the first scope refinement and scope variation that was submitted, and only minor changes were required as a result of this review. The Sponsor Delegate also has a background in cost engineering.

Scope variations and where major design changes are required fall within the contract variation / scope change management process. We understand there is a substantial dependency on the Transpower Technical Manager for the direction and finalisation of the design work. However, review participants noted the Technical Manager is pragmatic and has been involved with the project since its conception, as well has having had in excess of 16 years experience within Transpower. We understand there is a healthy tension between the ETC for cost and time control, versus the Technical Manager’s responsibility for quality, where discussion is welcomed.

We note there have been recent scope increases include the need for a rain-water filtration system to meet Manukau city Council resource consent requirements (due to a concern over heavy metal levels in measured rain-water runoff from the site), and ongoing problems with the relocation of the Contact Energy sewer main.

In summary, we find the project has in place a thorough scope definition and scope change management process which should ensure scope is appropriately managed within time, cost and quality constraints.

We have no recommendations for this section.



Time / Schedule

Rating Effective controls / activities, minor issues identified or some compensating controls exist.

Findings

Status

The project is currently in the delivery phase and on track for the March 2010 commissioning date, although slippage due to the late awarding of the DB1 contract and Areva’s delay in securing a subcontractor means review participants note the timeframes are now tight, but still achievable. We also understand the DB1 schedule contains no schedule contingency and has complex, concurrent parallel near critical paths, with dependence on outage availability and other associated risks detailed below. Accordingly the risk of slippage is high, and this is appropriately recorded within the PMP and the risk register.

A number of critical tasks have the potential to delay the project. AREVA advised they believed that the relocation of existing services (cables, communications, water and waste water services) were program critical.

From a technical point of view the delay in manufacture and delivery of the HV Cable test set was agreed by all interviewees as potentially able to significantly delay the testing of the 220kV cables and impact the project end date.

Transpower understand that the GIS and Control Building is also likely to become critical. The impact to the overall project program has been caused by the late award of the building construction contract. The completion of the substation building is critical as it houses the GIS switchgear and control and protection systems.

There were varying opinions received from interviewees regarding other critical program tasks, although we note the ETC appears well aware of these tasks and their critical nature.

The project is currently facing a problem with the relocation of the Contact sewer / stormwater pipe and other services. This is registered as an issue and all parties are working to resolve this.

Schedule

The scheduling procedure is outlined within the document entitled ‘ODP01 Scheduling procedure’, and specifies that projects schedules must be built up by the vendors based on a logically structured work break down structures.

The master project schedule was based on timeframes developed in the Solutions Study report, and further refined based on schedules developed with the vendors. Vendor schedules are further refined in detail by way of an iterative, ‘rolling wave’ approach as the project progresses (e.g. Maunsell releases new design works and further planned outages are secured, etc), although high level detail and critical milestones remain the same within the master project schedule, which was based lined on 1 August 2008 soon after the award of the DB1 contract and finalising the schedules with Areva.

We have reviewed a series of project schedules for each of the associated contracts, the Transpower overall contract program and an integrated schedule. In general, the project schedules are comprehensive and effort has been applied in identifying all pre-requisite tasks. Given the situation that the substation design work is being carried out in parallel with construction, it would be appropriate to further break up the design tasks and identify key approval hold points.

This has been addressed comprehensively in the AREVA program with up 82 separate approvals with Transpower identified to date within the AREVA schedule. The ETC notes this is part of an ongoing stream of several hundred technical approvals managed by the Technical Manager and his Technical Support team. Accordingly while this large number of separate approval activities and their associated durations provides a challenge for Transpower, the ETC states it is an integral part of the Transpower approach to the technical management of the project and notes that the technical team have provided an excellent turnaround of approvals and information to date.



A review of all project program tasks was undertaken and a number of long duration tasks were identified. It is considered that if the duration is long then it is possible that the work breakdown for these tasks could be longer or shorter than the duration identified. Examples of long duration tasks from the AREVA program include:

1. AIS Equipment testing – 10 weeks

2. Secondary Systems Testing – 6 weeks

It is possible to breakdown the secondary system testing into task of durations from 1-4 days as a minimum. A similar breakdown is possible for segments of the AIS testing.

All interviewees advised that the duration of these tasks were reasonable but it is possible for these activities to overrun. It was pointed out that further more detailed testing programs and plans would be developed well in advance of this testing.

It was apparent that there were many program tasks dedicated to installation of the earth grid for the substation but no specific task identifying the final testing of the earth grid and linking this as a pre-requisite task to further 220kV cable, AIS and GIS livening and testing activities.

As discussed in the interviews, the substation is utilising GIS and as part of any typical substation, there is a detection system installed to detect the presence of SF6 leakage. A program item to identify the installation and subsequent testing of this detection system was not found on the program. It would also be a pre-requisite for installation of the GIS equipment in the GIS and control building.

Monitoring of the schedules and their interdependencies is performed through ‘Coordination’ meetings run by the ETC, and within the vendor status reports. A rolled up GANTT chart is also reported to the bi-monthly Steering Committee meetings.

Scheduling is backwards looking based on planned network outages the project is able to secure for commissioning purposes. A key risk is whether the project can secure enough network outages of the required duration to successfully complete all commissioning activities on time, which could be materially impacted if there is a dry winter.

In summary, the project has established robust scheduling procedures and detailed schedules are in place, with the need to adhere to these standards understood by all parties. We have identified only minor improvement opportunities.


1.6 Review the schedule

Conduct a peer review of the project schedules focusing:

- specifically on design hold-points.

- long duration tasks. e.g. the Areva testing timetable and reduce or breakdown any long duration testing tasks. e.g. secondary systems testing

- for any missing tasks, such as the SF6 gas activities.

Medium Engineer to Contract Apr 2009

1.7 Sensitivity Analysis on Durations

Rather than focusing specifically on the critical path, consider applying some sensitivity analysis to the durations of the next most critical items including GIS and control building construction and relocation of services, to allow stakeholder expectation management.

Low Engineer to Contract Apr 2009



Cost / Budget


Findings

The project has regulatory approval from the Electricity Commission for up to a $99M spend limit. The Transpower Board approved a budget of $83M in September 2007 based on the P50 estimate in 2006 dollars. The budget has recently been approved to increase to $99M, (which is still within the MAC) based on a recent board paper that reported costs increase due to an increase in the cost of earth works and the final negotiated DB1 contract, with current estimated total spend at $97M.

The project budget has been appropriately mapped back to the project work breakdown structure.

As per Transpower procedures, the project was set up via the Transpower Maintenance Management System (MMS). The ETC raised a concern about MMS being administratively cumbersome to operate, primarily as it is a maintenance based system and does not easily allow for project related expenses and/or variations. For example, it has idiosyncracies in that a variation in cost has to be entered as a separate work order – which needs to be negative in value if the final cost for the original item is less than allowed for – and therefore also generates unnecessary approval requests.

To make the system work, the ETC held workshops with Transfield to develop commercial management procedures to match and notes these procedures could be rolled out to other projects of similar size and scale where construction contracts are awarded prior to finalisation of designs. Although the ETC noted it would be preferable and easier to use a Financial Management Information System first for project costs, and then pro rata to MMS upon capitalisation of the project.

The project also has project specific systems for forecasting and reporting (the project cost control workbook), with vendors understanding what inputs are required from them (especially in terms of invoicing).

A number of management summary cost reports are produced by the project, including summary costs, financial year summaries, work package cost status (which compares against PAD budget, current budget, forecast, commitments and actual plus variance) and also an S curve summary.

Cost control procedures for scope refinements and scope variations is a key component for controlling costs within the project, particularly given the situation where enabling works commenced before the scope was fully defined. These procedures are discussed within the Scope section above.

Procurement cost management is through engaging the Transpower procurement team in the purchase of items outside of scope of the main vendor contracts.

We find cost control and reporting to be robustly governed and managed by the project.


1.8 Consider the use of FMIS for future projects

For future complex Transpower construction projects, consider the use of FMIS for project costs and then pro rata across to MMS at appropriate project capitalisation points.

Medium Sponsor N/A



Resources


Findings

The PMP defines the core management team project structure, (see Appendix B – Project Team Management Structure) and required skills and resources.

Resourcing is mainly through the use of contracted resources via the main vendors, and from the Transpower internal design team and supporting resources, with the requisite skills and resources specified within the vendors project management / quality plans.

For the larger contracts of work, vendors have been engaged using the Transpower-modified FIDIC Yellow Book standards, with all other contracts following Transpower's suite of contract conditions depending on contract value.

We understand Establishment workshops were held for the Enabling Works and DB1 contracts immediately following their award to establish contract specific management objectives including responsibilities, processes, key drivers, KPIs and core values, including safety. It is noted that there will be a lot of interaction required between Areva and Transfield on protection and civil works. Both Transfield and Areva have established site offices, with the former providing desk space for Maunsell and the Transpower project management team to use as and when required.

The ETC plays a prime contract management function and is in charge of reviewing scope refinements, contract variations, and any commercial issues that may arise. He also chairs the project coordination meetings. Daily site activities are managed onsite by the ETC Representative, who meets with both Areva and Transfield onsite representatives on a daily basis as required.

The Technical Manager acts as the gate between releasing approved designs for construction between Maunsell and Transfield, and as the point of approval for the Areva designs under the DB1 contract, as outlined within the PMP. We understand that there is a healthy level of interaction between the Transpower Design Team, onsite power technicians and Transfield Resources, who proactively feed through pragmatic solutions and design feedback to the Maunsell Design. Additionally, Maunsell designs are first reviewed by Transfield for their practicality / constructability as part of the peer review process.

Areva have also reported a high level of support from all parties, with recent design workshops held at Areva’s office in Sydney. Although they are new to Transpower for this type of work, risk is mitigated through a comprehensively detailed and scoped contract and regular meetings.

Skilled resources are encouraged through existing long-term relationships with Transfield and Maunsell, both of which who are preferred suppliers. Additionally, the Project Director for Maunsell is the account manager on the Transpower account and therefore has an overview of all Transpower design work, which allows him to prioritise resources and work, as and when required. He additionally can request design resources from Australia when required.

Maunsell did question whether the competitive tendering process for design packages outside of scope was necessary. We understand the three RFP packages went through a 6-8 week tender and evaluation process, where this time could have been used for resource-levelling within Maunsell. While there is an understanding Transpower has internal requirements for tendering work above a certain value, there was a question as to whether this process could be streamlined. We understand that the Maunsell Project Director has previously been seconded to work for the Transpower Northern Projects Manager, and so Maunsell have an excellent understanding of the Transpower environment.



Transfield also advises that with the current building slow-down, they have more than an adequate supply of skilled resources for this project.

Areva are well resourced with access to resources worldwide; additionally the Project Manager used to be a protection and control engineer. Areva report there is a high level of cooperation with the project team, and provided the example of Transpower’s assistance in helping gain resource consent for the GIS building construction.

All review participants have indicated that the ETC has been careful to use the performance KPI’s as a way to keep parties motivated and focussed on key deliverables and timeframes, and that they are being used effectively in this manner. We understand KPI’s are used as a trending tool and are discussed at the Steering Committee. As noted earlier, the KPI reporting process should be recorded within the PMP.

In summary the project appears adequately resourced with good team morale, and review participants across all the parties have expressed a shared common view and commit to the objectives of the project, along with the requisite level of cooperation.

We have no recommendations for this section.



Safety Management


Findings

Transpower has a strong emphasis on safety, and it serves as a core principle for this project. This focus is also one of the core functions for Transpower Project Manager, who has delivered Transpower’s “Keys to Life2” safety training to the vendors and staff on the project in group training sessions. The project has also developed ‘safety’ KPI’s for the project, which are included within the monthly vendor status reports and monitored by the Project Manager.

Key documents have also been developed by both Areva and Transfield for safety and emergency plans, and environmental management planning. The site managers also conduct daily site meetings prior to commencing civil works, and a hazards notification board is managed onsite, and Transpower have safety assessors who perform site safety assessments as required, dependent on the level of activity on site. It was noted by some review participants that some of the Transpower safety assessors take a constructive feedback approach, whereas others could be coached more in this method so as to engage more effectively with onsite project team members.

Additionally, there are outage planning review meetings that are conducted prior to each commissioning / planned outage, where safety is also discussed.

As a number of safety incidents have occurred in September 2008, we reviewed the site safety plans from AREVA and Transfield Site Management Plans. The documents were comprehensive and addressed the majority of substation and transmission line construction specific issues.

As this substation involves a 220kV cable and associated cable trough, some additional safety issues related to this type of installation should be highlighted. A revision to the AREVA Site Management Plan, required by Transpower, related to the required competency and capability of resources working in up to 3 areas of the construction site which include the GIS, AIS and cable trough areas. AREVA’s approach to this was to ensure that all resources were fully competent for all areas.

Transpower has dedicated some effort to review specific site management plans and propose amendments to the contractors. A preferred approach is to conduct an “endorsement process” where the Transpower safety assessment group separately endorse each contractor identifying shortcomings and resolving inconsistencies in safe working practices and plans, followed by routine field validation audits. This two stage process is an accepted practice for large transmission operators in Australia. The endorsement process may be valid for several years.

During the interviews, the issue of management of SF6 gas was discussed and as part of the site safety issues KEMA was advised that the placement of SF6 detection systems on site is part of the construction project. It was unusual that the issue of detection, collection and containment of SF6 is not mentioned in either of the site Management Plans. It is a low risk hazard but as detection systems are in place it should be highlighted in the plan.

We also understand there was a possible failure to immediately report a safety incident that occurred earlier this year, in part prompting the commissioning of this review. We understand the incident was brought to senior management’s attention (on the same day) by way of an ad hoc update at a project function. Senior Management immediately brought this to the Transpower CEO’s attention; fortunately the consequences of this incident were minor. We note that the standard timeframe for safety incident reporting is within a 24-hour period, and it is unclear from review participants whether this was breached.

2 See also Transpowers “Keys to Life” safety brochure.



We understand, however, that the ETC and Project Manager are more than aware that safety incidents need to be immediately reported to the Sponsor Delegate and Sponsor (who will in turn report this to the CEO), and this has also been reinforced to the vendors.

We also understand that soon after the safety incident occurred, the Project Manager presented the ‘keys to life’ Transpower safety training to some 70x Transfield staff and contractors, and an article was also published in the Gridlines journal the month after.

In summary, we find Transpower’s strong emphasis on site safety is appropriately understood and echoed by its vendors, with a site visit where it was evident site safety is treated with paramount importance. Safety procedures appear robust, with only minor areas for improvement.


1.9 Coaching of Transpower Safety Assessors

Consider coaching safety assessors to ensure that all are engaging in a constructive feedback approach, rather than ‘penalty-based’ approach.

Low Construction Manager

Mar 2009

1.10 Consider a ‘Safety Endorsement Process’

For future projects, consider conducting an “endorsement process” whereby the Transpower audit group separately endorse each contractor identifying shortcomings and resolving inconsistencies in safe working practices and plans, followed by routine field validation audits.

Low Construction Manager

Mar 2009



Risk & Issue Management


Findings

Risk Management

Project risk management is carried out in accordance with the Australian and New Zealand Standard for Risk Management (AS/NZ 4360).

Two risk registers are maintained – one orientated towards Enabling Works and which is maintained by Transfield on their project intranet site. The second is orientated towards the DB1 contract and is maintained on the Transpower project intranet site. All project team members have read access to the Sharepoint sites, which also records assumptions expressed as risks.

The two risk registers provided (design and build and Enabling works) are comprehensive and identify typical risks associated with a large transmission substation construction.

Some of the risk descriptions are not actual risks to the substation or the project. For example R-112 "New Product familarisation" is not a risk in itself. A complete risk description for this case would be "A lack of training on a new product leads to inadvertent protection trip or mal-operation".

Some of the risk mitigation strategies require some attention. With reference to R-113 "Test equipment failure", the risk mitigation states an action "ensure all test equipment has current calibration". This is a quality issue and there would be an assumption that any test equipment with an "out of date" calibration certificate would simply not be used and unavailable for use under all circumstances. A suggested risk mitigation description would be to "make available/procure alternative test units".

R-120 states "Primary injection causing loss of supply" has a mitigation of "Test procedure for high risk primary injection test. Check list ensure all isolation switches action correctly. Peer review of test plan." Unfortunately, this risk mitigation description in this case is merely re-stating a process which is already part of the quality and safety systems that are in place. In general, a ‘risk mitigation’ should be some form of additional check or measure, in this case it would be to overlap an existing process in the event that that existing process is not appropriately applied or overlooks an issue.

A suitable overarching risk mitigation may be to arrange with the control room that it is possible to carry out some emergency switching which would quickly restore supply and minimise the overall impact of any interruption.

We reviewed the risk ratings of all the risks in the “design and build” and “enabling works” risk register and advise that it was unusual that up to 6 currently "open" risks are assigned an EXTREME rating. In our opinion, R-076 MAD 4m correctly incurs a "Catastrophic" consequence while the other EXTREME-rated risks are almost all of "Moderate" consequence, thus a risk assessment of HIGH is more appropriate.

It is also unusual that two EXTREME-rated risk have a likelihood of "almost certain". Risk R-008 "concurrent design and build" could have a likelihood of LIKELY given there is significant effort applied to co-ordinating design and building activities. With respect to R-189 "non-constructability of the sewer line" a comment provided on the register indicated that a solution "will be found". Under this basis, in our opinion, it should have a "Possible" likelihood, thus a risk assessment of HIGH is more appropriate.

It was noted in reviewing the risk ratings that some identical risks were assigned different ratings on the different registers. Interviewees from AREVA and Transpower were challenged on this issue but were of the opinion that from each organisations point of view the consequence and likelihood could be different.



Transpower has developed a series of standard designs for specific sub-systems in the substation. These designs specifically developed on other substations have been forwarded to the design contractor to provide the basis for Otahuhu substation designs (e.g. bus section design). Selection of the GIS switchgear has been done after visiting the manufacturer and confirming their suitability for Transpower.

Taking into consideration this conservative approach, it is clear that the project program includes sufficient duration but there are no specific tasks or contingency identified for additional training or familarisation of new products. It is noted that the risk register did include a familarisation risk R-112.

Interviewees were asked whether Otahuhu substation presented any additional challenges over typical substation constructions completed by Transpower:

1. Otahuhu is a switching substation so there are no large transformers (apart from station services) and no capacitor or reactor banks to separately commission. The absence of these items in a transmission substation reduces the complexity of the design and reduces overall testing time.

2. The main difference identified was the utilisation of a 220kV cable provided in an enclosed ground level cable trough. Testing and commissioning this type of cable required specialised HV test set which is due to be supplied under this contract.

There are some technical risks associated with SCADA, security system, condition monitoring systems, communication system service risks that could be included. We have listed these within the recommendations section below.

Review participants noted that some of the key risks were seen as:

• Site Safety

• Interruption to supply – especially during the commissioning of the programmed / automated system / protection circuits

• Incorrect Panel / Protection Circuit design

• Whether the project can secure enough network outages of the required duration to successfully complete all commissioning activities on time, especially if there is a dry winter.

• Reliance on third parties to move buried services for the cable trenches (e.g. Telecom, Gas etc).

• Delivery of hardware, such as the high voltage cables.

Issues Management

Issues management is through raising issues at formal project meetings, which are then tracked within an actions point register. Each specific project meeting type, (such as the Management and Engineering Coordination Meeting Actions report) maintain an action point register. Major issues from across all action point registers are then summarised and reported up to the Steering Committee. Within the PMP it notes that while this is currently working adequately, it will be monitored in case an issues register should be developed.

Current major issues include difficulties with relocating the Contact sewer pipe, relocation of buried services for cable trench work, and the late engagement of Areva and late engagement of Areva’s subcontractor. Review participants noted that issues are transparent and dealt with appropriately by the ETC and Transpower Project Manager.

In summary, the project has established a robust safety, risk and issues process with minor areas for improvement.




1.11 Review the Risk Registers

Review the risk registers for the following:

- Re-write the risk identification descriptions where the description is not linked to an event at the substation or a subsequent substation event.

- The risk mitigation description should not include any existing quality or safety controls. In similar risk register these are covered in “Existing controls” and the mitigation becomes an overarching action.

Low Engineer to Contract Mar 2009

1.12 Add additional risks

Add the following risks to the risk register:

- Not all alarms are identified and captured in SCADA database leading to no warning of imminent plant equipment failure

- Incorrect limits set in SCADA due to incomplete protection design leading to plant overload condition

- Incomplete substation design requires a re-visit of the SCADA database completeness delaying commissioning

- SCADA and protection systems not well integrated leading to lengthened testing

- Substation auxiliary systems not fully captured in SCADA reducing substation availability

- Key person dependency risk for the Engineer to Contract and the Technical Manager

- New Product Familiarisation – That a lack of training on a new product leads to inadvertent protection trip or mal-operation.

Low Engineer to Contract Mar 2009



Integration


Findings

Dependency Management

The PMP lists key external dependencies as:

- Local authorities, for resource and building consents

- Contact Energy, as owner of the neighbouring power station

- Other utilities, including Vector, Telecom, Watercare and Manukau Water for relocation of their services to accommodate the works.

The project relies on managing these external dependencies through the project scheduling process, with associated communications.

Design dependencies between Areva and Transfield / Maunsell designs are coordinated through the Transpower Technical Manager signing off the technical decisions, reviewing designs, and being a part of the coordination meetings. Construction inter-dependencies between the vendors are managed by the ETC along with the vendor project managers in fortnightly Coordination meetings, through an integrated project schedule and the Otahuhu Diversity Project interlinks schedule, and through respective site management plans, with clear demarcations within the designs as to what party is responsible for what.

Overall inter-dependencies are communicated through the two-monthly steering committee meetings.

We note there is no dependency register for the project, instead dependencies are managed via scheduling and the PMP.

The review participants noted there is a high level of complex task interdependencies, but that these are being managed well by the ETC and Project Manager through the processes put in place. However despite this, we note that for a project of this size and to minimise a key person dependency risk on the ETC, we would expect to see a dependency register as this would formalise the close communication with relevant stakeholders, and enable the project to identify and agree with stakeholders timeframes within which projects affected by conflicting priorities will be delivered.

Organisational Impact Assessment

The project is largely independent of other Transpower projects, and is mainly impacted by the availability of planned outages for commissioning works. This is managed by advance planning and the early submission of outage request plans, plus close liaison with the System Operator. At the time of the field work for the review, we understand the Project Team were undergoing a period of planning to incorporate the latest information available on planned outages.

As the nature of the project is the diversification of an existing switchyard, the organisational impact upon Transpower will mostly be upon the System Operator and the operational and financial aspects of the new asset within the Grid Performance area. While there is a section within the PMP that discusses the Asset Owner, it only looks at the “Operational Acceptance in accordance with standard Transpower Procedures”, and should include (or refer to standards or a strategy that will cover) the following::

• Ongoing consultation with the Asset Owner and System Operator

• Processes for handover into BAU (including the development of BAU operational procedures and training)

• The transfer of issues from an issues log (if any), into BAU.



• Development with the Asset Owner of BAU operational acceptance criteria (including testing and commissioning strategies)

• Arrangements for ongoing maintenance upon project completion (such as As-built documents, proposed maintenance contracts, etc).

While these are more likely to be well defined and understood processes within Transpower, it is important to summarise and refer to these within the PMP to ensure adequate consultation is undertaken and approvals are secured.

Additionally, it was noted the project is unique in a number of ways from standard Grid Asset projects in terms of having a steering committee, utilising a vendor new to this part of Transpower’s business (Areva), and implementing building works prior to the scope being fully defined. As such, it would be beneficial to establish a lessons learned register to capture the new learnings and assist in knowledge transfer within the wider Transpower project management team.

In summary, the project is tracking dependencies through senior representation on the Steering Committee, the inter links schedule report, and attendance by the ETC and Transpower Project Manager at a variety of meetings. However more formal tracking could be achieved through the development of a Dependencies Register. Interaction and impact upon the Asset Owner by the project needs to be more clearly recorded, and it would be beneficial to establish a lessons learned register.


1.13 Dependencies Register and Communications

Consider developing a Dependency Register, to bring a level of formality to the communications between the project and key stakeholders for the interdependencies, so that requirements can be formally aligned, and promote communications to be clear, transparent and regular.


1.14 Organisational Impact – Asset Owner

Ensure planning and proposed tasks for transfer into BAU are recorded within the PMP and supporting documentation, such as consultation with the Asset Owner, development of training and support procedures, transfer / acceptance of known issues, develop of ongoing maintenance contracts and procedures, etc. Involve the Asset Owner further within the project.

Medium Project Manager Dec 2009

To

Mar 2010

1.15 Establish a Lessons Learnt Register

Consider establishing a lessons learnt register to capture the learnings from dealing with the unique new situations within the project, such as Areva operating in this space, utilising a steering committee, and the new MMS procedures, to name a few.




Communication

Rating

Effective controls / activities, minor issues identified or some compensating controls exist.

Findings

Internal

The Transpower Project Manager has formal responsibility for communications, with the ETC performing a supporting role. The project does not have a communications plan, instead these aspects are adequately covered within the PMP and specifically developed communication procedures. It is noted that the need for a communications plan will be reviewed as the project progresses, and we strongly endorse the need to monitor this.

The Steering Committee, Enabling Works Management Team, and DB1 management team (see Appendix B) are the main ongoing forums for project communication. Other forums established by the project and denoted within the PMP include:

• Project Coordination – Meets monthly to identify and coordinate interdependencies between the projects, with a focus on medium to longer term planning;

• Site Coordination – Meets weekly, complements the Project Coordination meeting with a focus on ‘real time’ and short term issues;

• Enabling Works Technical – Weekly or as required to address real time and technical issues.;

• Enabling Works Protection – Meets weekly or as required to address design and construction liaison on enabling works protection issues;

• DB1 Design – Meets as required between Transpower Technical Manager and Areva for design input and review approval of DB1 design work;

• Site Safety Coordination – Held weekly between Transpower, Areva and Transfield, with a focus on safety management and coordination of site activity between the parties;

• Risk Workshops – convened monthly or as required for both DB1 and the Enabling Works. The Transpower Project Manager also has weekly meetings with the Northern Projects Manager, who in turn keeps the Sponsor Delegate updated. However, these are informal meetings as part of the line management functions of these positions and as such are not recorded within the PMP. In addition, PSRs are provided to the Transpower Grid PMO and the Steering Committee, and each work stream project manager (i.e. DB1, Enabling Works Construction, Enabling Works Design) also produces regular reports to the ETC and Transpower Project Manager. The Sponsor Delegate in turn provide updates to the Sponsor who includes this within his standard monthly report to the CEO, who then consolidates these views and reports on the project (along with other projects) to the Board.

We have reviewed the communications procedures developed by the project and visually inspected the sharepoint sites. We find they are appropriate for a project of this size and complexity, and in particular with dealing with a multitude of external parties.

We note the sharepoint sites contain the risk register and key project deliverables, such as the Solution Study Report, progress reports, design drawings (and version control) etc. It is used effectively by review participants as a means of version control and is an excellent means for the efficient reference and storage of documents.



The project also utilises a formal email ‘transmittal’ system, where formal emails and transfer of records are provided a transmittal identifier number, registered and tracked in a correspondence log, with the sending party responsible for updating the log and placing a copy on the Transpower email repository.

Standard forms have also been developed by the project to support communication, and are described within OPD04. They include: Contract query, design query, RFI, Document Transmittal, Notice to Contractor and Variation Orders.

In summary, we understand from review participants that the level of informal internal communications is very good and a key requirement for a project with this level of interdependencies, safety requirements and where two competing vendors have been engaged onsite. It has been noted that the ETC has done an exemplary job, along with the Project Manager, in establishing these forums and procedures.

External

We note there is no external communications plan; instead the PMP notes that the communication requirements for each stakeholder is already established or are sufficiently clear.

The project is appropriately described on the www.gridprojects.co.nz website, with the general public able to subscribe to receive updates. A good level of information is provided and updated recently, notably with photos from October 2008 civil works.

The Project Manager is assigned responsibility for prime external communications on Transpower’s behalf, with a key stakeholder being Contact Energy, (who has a generation station next to the project site). We understand Transpower has entered into a commercial arrangement with Contact that this project will not impede Contact’s abilities to generate electricity or distribute this through the Otahuhu substation; we understand this is monitored closely by the Transpower Project Manager, however there is no mention of this within the PMP or project management documentation provided to us.

Along with informal weekly phone calls to Contact as required, the only formal meetings within the PMP are denoted as the Contact Energy Liaison, which meets monthly or as required to manage issues with Contact Energy as neighbours and is chaired by Transpower Project Manager (with Areva and/or Transfield attending as required).

Further, Transfield have reported they have been able to make good use of their existing relationships at engineer level within Contact Energy to assist in relationship management.

Given the concerns over reputational risk should an incident occur, the opposition by MEUG to the project, and the nature and size of the project, we consider that an external communications plan should be developed. This plan should identify and assess stakeholder needs, assign liaison responsibility, develop the key messages for the project and be developed in conjunction with the Transpower Communications department. This would help ensure there are consistent, planned and regular communications across all stakeholders that meet their needs, and will help ensure manage expectations and potential opposition of stakeholders. This will become increasingly important as the potential for outages and safety incidents increase as the site moves into the commissioning phase.


1.16 Monitor the Effectiveness of Internal Comms

Continue the monitor the effectiveness of internal communications and periodically re-assess whether an internal communications plan is required.

Low Project Manager Ongoing

1.17 Create an External Communications Plan

Develop an external communications plan to identify and assess stakeholder needs, potential impacts, assign liaison responsibility, and develop the key messages for the project. This should be developed in conjunction with the Transpower Communications department and should include the external website, Contact, the media and MEUG.




Quality Management


Findings

The project has no separate quality plan. Instead a requirement for quality control is specified as a requirement within the RFPs, and within the vendor contracts. Additionally the vendors are ISO9000 accredited and are required to adhere to Transpower standards and policies for this type of work.

The PMP describes a number of procedures to ensure quality management across all aspects of the project, including KPIs that include quality measurements, and a deliverables register is maintained with the Areva document tree for the DB1 work, and the Maunsell Drawings list for the Enabling Works.

Bearing in mind that quality is an essential item for the project to minimise the risk of outages, and while we are satisfied there is a robust quality process in place for all project work, we feel it would be beneficial to have this outlined within one document (such as a quality management plan), or alternatively detailed in greater depth within the PMP.

Design Work

We understand all designs (both Areva and Maunsell) must be approved by the Transpower Technical Manager, prior to implementation, who compares this against the overall Solution Study Report and the project’s Technical Objectives (i.e. safety, ongoing ease of maintenance, conformance with Transpower’s standard designs and overall design philosophy).

Each design work package contains a brief, any applicable Transpower design standards and detailed drawings from similar components that have been implemented before (i.e. standard designs).

All Maunsell designs undergo a drawing and design check, after which a high level peer review is applied. Where the designs are not based on standard Transpower designs, they are passed to an external reviewer (agreed with Transpower), who performs an in-depth review.

Additionally, these Maunsell designs are then reviewed by Transfield for their practicality / constructability. The Maunsell design work is also conducted by the Transmission and Distribution Department, with 90% of its work sourced from Transpower. Maunsell reports daily contact with the ETC for decisions and guidance on design work, along with the Technical Manager and appropriate departments within Transpower as required. The majority of the work is based on existing Transpower approved designs, with modifications based on the specifications of the hardware purchased by Transpower. It is noted that the designs are undergoing a stricter review process than for other Transpower work, due to the complexities and criticality of the designs.

Maunsell reports the quality of the design inputs has been sufficient; whilst there has been some delay on occasion, generally it has been good. Where further detail is required, Maunsell also employs subcontractors for site inspections to determine further design input details. Maunsell reports that the designs produced in Auckland are peer reviewed by its Wellington office, and vice versa. Maunsell also has a quality management plan that they are adhering to, and are ISO 9000 accredited.

Construction Works

Actual construction of minor civil works is accepted onsite by the ETC, supported by the Engineers Representative, as to the Design Drawing specifications and against appropriate acceptance criteria specified within the contracts.

In Summary, while review participants agree a high emphasis has been placed on quality and approval of deliverables, this is specified across a number of documents and it may be beneficial to summarise this into a quality management plan.




1.18 Develop A Quality Management Plan

Consider developing a quality management plan which pulls into one place:

- The standards against which project deliverables will be measured, (such as acceptance criteria, applicable Transpower design standards).

- References to the acceptance criteria as described within the various contracts;

- Roles and responsibilities for quality acceptance within the project team (i.e. peer review signoffs; who’s responsible for quality overall);

- What will trigger the requirement for independent peer reviews of critical work designs, etc.

Medium Project Manager Mar 2009



Appendix A – Project Documentation

PM Attribute Documentation

Last 4 Steering Committee Status Reports

Last 4 Steering Committee Meeting Agenda & Minutes

Last 4 Governance Committee Status Reports

Last 4 Board Papers

1. Governance & Management

Agenda & Minutes for any Internal or External Advisory Groups

Business Case

Project Management Plan 2. Scope

Scope Change Register

Work Breakdown Structure

Project Schedule (MS Project) 3. Time/Schedule

Last 4 Project Team Status Reports and Meeting Minutes

Budget

Cost/Benefit Model

Budget/Cost Tracking Spreadsheet 4. Cost/Budget

Last 4 Cost/Variance/Forecast Financial Reports

Project Structure Chart 5. Resources

Resource Management Plan

Risk Register

Issues Register 6. Risks & Issues

Escalation Report(s)

Communications Strategy and/or Plan

Stakeholder Analysis & Engagement Plan 7. Communication

Stakeholder Communications Activity Log

Dependency Chart or Dependency Register

Organisation Impact Assessment/Management Plan 8. Integration

Training & Service Support Plan

Quality Management Plan

Deliverables Register

Lessons Learned Register 9. Quality Management

Historic Independent Quality Assurance Reports



Appendix B – Project Team Management Structure